WO2020263829A1 - Amino acids and their derivatives for improved oil recovery - Google Patents

Abstract

Described herein are compositions, techniques, methods, and systems for use in and for producing hydrocarbons from a reservoir. The disclosed compositions, techniques, methods, and systems employ fluid mixtures including amino acids which may modify characteristics of rock in the reservoir to improve hydrocarbon production. For example, amino acids may be useful to change wettability character of rock surfaces from a more oil-wet condition to a more water-wet condition.

Description

AMINO ACIDS AND THEIR DERIVATIVES FOR IMPROVED OIL

RECOVERY

CROSS REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of and priority to U.S. Provisional Application 62/865,773, filed on June 24, 2019, which is hereby incorporated by reference in its entirety.

FIELD

[0002] This invention is in the fields of enhanced and improved oil recovery. This invention relates generally to compositions, methods, techniques, and systems for producing hydrocarbons and enhancing hydrocarbon production from subterranean reservoirs.

BACKGROUND

[0003] Waterflooding is useful for supporting the rate of oil production from a subterranean reservoir, and may be used to increase oil production rates and the oil recovery factor as reservoirs are depleted. The injected water may be produced water or brine previously produced from the reservoir or from another reservoir, and seawater, freshwater, or aquifer water may also or alternatively be used. The water may be injected at a distance away from a production well to provide a driving force for displacing oil in the reservoir toward the production well and may be useful for maintaining pressure within the reservoir as oil is produced.

[0004] In some cases, some oil within a reservoir may not be easily available for extraction, such as if the oil is trapped within pores of the rock within the reservoir. Techniques for producing oil from porous rock exist, but they may be complex or require use of surfactants, solvents, or other costly additives that may not be environmentally friendly.

SUMMARY

[0005] Various techniques are described herein for producing oil or for improved oil recovery that employ injection of aqueous fluid mixtures into a subterranean reservoir. The aqueous fluid mixtures include one or more amino acids, which may be useful for modifying the wettability of rock within the reservoir to improve the availability and production of hydrocarbons contained within pores of the rock. Since amino acids tend to not be naturally occurring within subterranean reservoirs, the amino acids can also or alternatively be used as a tracer to track fluid movement within the reservoir and identify well connectivity in order to maximize sweep efficiency of waterflooding operations. Advantageously, amino acids can be easily characterized and quantified using spectroscopic techniques, such as nuclear magnetic resonance or liquid chromatography- mass spectrometry. Moreover, amino acids tend to be environmentally benign, easily produced, and available at low cost. [0006] The present techniques overcome challenges in recovering oil or hydrocarbons from a subterranean reservoir because the presence of the amino acids in the injected fluid mixture may modify a wettability of rock surfaces within the reservoir to change the rock surfaces to a more water-wet condition (less oil-wetting condition), allowing for hydrocarbons contained within pores of the rock to be more easily released. Certain conditions may contribute to the wettability modification, such as using amino acids that have particular electrochemical characteristics when in the reservoir. For example, amino acids that are especially advantageous include those having an isoelectric point (pi) that is less than a pH of an aqueous phase (e.g., brine) in the subterranean reservoir. When such amino acids are present in the aqueous phase, the amino acids may be in a deprotonated form and carry a negative electrical charge.

[0007] The disclosed fluid mixtures may alter the rock wettability to favorably allow

hydrocarbon release from the reservoir, and in many cases without using or in the absence of surfactants present in the fluid mixture. In some cases, however, it may still be advantageous to include surfactants in the injected fluid mixture. Eliminating or reducing the use of surfactants may have a further beneficial effect, as stabilizers normally used to maintain stability of surfactants also do not have to be used or used only to a lesser extent, reducing the complexity and cost of the fluid mixture. The fluid mixture may also include other components, such as solvents, which can favorably interact with the hydrocarbons within the reservoir, such as to reduce the viscosity of the hydrocarbons and allow for easier and/or more efficient production.

[0008] In a first aspect, methods for producing hydrocarbons are disclosed herein. In an example, a method of this aspect comprises obtaining a fluid mixture comprising water and an amino acid, such as an amino acid that has an isoelectric point (PIAA) less than a pH of brine in a subterranean reservoir; injecting the fluid mixture into the subterranean reservoir, such as to allow the fluid mixture or a component thereof to contact rock surfaces in the subterranean reservoir and optionally increase a water wettability character of the rock surfaces; and producing hydrocarbons from the subterranean reservoir. Optionally, a method of this aspect may further comprise determining the pH of the brine in the subterranean reservoir. Optionally, a method of this aspect may further comprise determining the amino acid based on the pH of the brine in the subterranean reservoir.

[0009] The use of amino acids in fluid mixtures used for producing hydrocarbons may provide a number of distinct advantages. For example, amino acids may be used as tracers to allow identification of fluid connectivity between wells in the reservoir, particularly since amino acids are not naturally occurring within subterranean reservoirs and are easily identifiable and quantifiable using spectroscopic techniques. Amino acids may also modify wettability characteristics of rock surfaces within the subterranean reservoir, depending on their isoelectric point (pi) and the pH of aqueous phase (e.g., brine) within the reservoir. When an amino acid having an isoelectric point lower than the pH of the aqueous phase is injected into the reservoir, the amino acid can become deprotonated, effecting a reduction of the pH of the aqueous phase and also acting as a buffer against further changes to the pH of the aqueous phase. As the aqueous phase’s effective pH is reduced to a level below the point of zero charge of the rock within the reservoir, the rock may change from an oil-wetting condition to a water-wetting condition. The point of zero charge of the rock may correspond to or be estimated as the pH where aqueous phases and oil phases equally wet the rock surface (i.e., where an oil phase contact angle with the surface is about 90° and where an aqueous phase contact angle with the surface is about 90°). In embodiments, it may be advantageous when the isoelectric point (PIAA) of the amino acid is less than a point of zero charge (PZCrock) of rock in the subterranean reservoir.

[0010] A variety of different amino acids are useful with the systems, methods, and fluid mixtures described herein. For example, the amino acids may include one or more a-amino acids, b-amino acids, g-amino acids, or d-amino acids, or other amino acids, alone or in combinations. The amino acids may include standard amino acids (e.g., biologically relevant amino acids) or non-standard amino acids. The amino acids may include different enantiomers (e.g., designated by L or D prefixes or (S) or (R) designators), and chiral mixtures may also be used. When no enantiomer or stereo designation is used herein, one, more, or all enantiomers may be considered as identified (provided a stereocenter is included in the molecule). For example, reference to a- alanine may include one or more of L-a-alanine or D-a-alanine. When no functional group location (e.g., a, b, g, d, etc.) is used herein, one, more or all functional group isomers may be considered as identified, if such isomers exist. For example, reference to alanine may include one or more of a-alanine or b-alanine. Specific amino acids that may be useful with the present methods, systems, and fluid mixtures may include, but are not limited to, alanine, arginine, asparagine, aspartic acid, cysteine, glutamic acid, glutamine, glycine, histidine, isoleucine, leucine, lysine, methionine, phenylalanine, proline, serine, threonine, tryptophan, tyrosine, valine, slenocysteine, or pyrrolysine.

[0011] The amino acids may be present in the fluid mixture at any suitable concentration.

Example concentrations of the amino acids may be from about 0.1 wt.% to about 15 wt.%. For example, useful total concentrations of one or more amino acids in the fluid mixture may be from 0.1 wt.% to 0.5 wt.%, from 0.5 wt.% to 1 wt.%, from 1 wt.% to 1.5 wt.%, from 1.5 wt.% to 2 wt.%, from 2 wt.% to 2.5 wt.%, from 2.5 wt.% to 3 wt.%, from 3 wt.% to 3.5 wt.%, from 3.5 wt.% to 4 wt.%, from 4 wt.% to 4.5 wt.%, from 4.5 wt.% to 5 wt.%, from 5 wt.% to 5.5 wt.%, from 5.5 wt.% to 6 wt.%, from 6 wt.% to 6.5 wt.%, from 6.5 wt.% to 7 wt.%, from 7 wt.% to 7.5 wt.%, from 7.5 wt.% to 8 wt.%, from 8 wt.% to 8.5 wt.%, from 8.5 wt.% to 9 wt.%, from 9 wt.% to 9.5 wt.%, from 9.5 wt.% to 10 wt.%, from 10 wt.% to 10.5 wt.%, from 10.5 wt.% to 11 wt.%, from 11 wt.% to 11.5 wt.%, from 11.5 wt.% to 12 wt.%, from 12 wt.% to 12.5 wt.%, from 12.5 wt.% to 13 wt.%, from 13 wt.% to 13.5 wt.%, from 13.5 wt.% to 14 wt.%, from 14 wt.% to 14.5 wt.%, or from 14.5 wt.% to 15 wt.%. In embodiments, a concentration of the amino acid is within (i.e., less than or about) a solubility limit of the amino acid in the fluid mixture at a temperature and a pressure of the subterranean reservoir. In embodiments when multiple amino acids are used in the fluid mixture, one or more or all of the amino acids may have isoelectric points less than the pH of an aqueous phase in the subterranean reservoir. In some cases, a mixture of amino acids with isoelectric points less than the pH of the aqueous phase and greater than the pH of the aqueous phase may be used.

[0012] The fluid mixture may optionally comprise a number of different components beyond water and the amino acid. For example, the fluid mixture may optionally comprise fresh water, seawater, reservoir connate water, produced water, or brine. In some methods, obtaining the fluid mixture comprises obtaining an aqueous solution and augmenting the aqueous solution with one or more additives including the amino acid. Optionally, the fluid mixture comprises 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, nitrogen, or carbon dioxide. Example surfactants may include an anionic surfactant, a cationic surfactant, a nonionic surfactant, an amphoteric or zwitterionic surfactant, or any combination of these. Example solvents may include a hydrocarbon, a hydrocarbon solvent, an amine, an ether, an alcohol, a ketone, or any combination of these.

Example acids may include hydrochloric acid or acetic acid. Example bases may include sodium hydroxide, potassium hydroxide, lithium hydroxide, ammonium hydroxide (ammonia

solution/aqueous ammonia), and/or amines. Example salts may include those comprising 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 of these.

[0013] Optionally, a salinity of the fluid mixture is greater than or about equal to a salinity of the brine in the subterranean reservoir. Optionally, a salinity of the fluid mixture is less than or about equal to a salinity of the brine in the subterranean reservoir. Specific salinities of the fluid mixture may be from about 500 ppm to about 250000 ppm. For example, a salinity of the fluid mixture may be from 500 ppm to 1000 ppm, from 1000 ppm to 5000 ppm, from 5000 ppm to 10000 ppm, from 10000 ppm to 50000 ppm, from 10000 ppm to 15000 ppm, from 15000 ppm to 20000 ppm, from 20000 ppm to 50000 ppm, from 50000 ppm to 100000 ppm, from 100000 ppm to 150000 ppm, from 150000 ppm to 200000 ppm, or from 200000 ppm to 250000 ppm. Optionally, a salinity of the fluid mixture is less than or about 100% of a salinity of the brine in the subterranean reservoir.

[0014] Optionally, a pH of the fluid mixture is less than or about equal to the pH of the brine in the subterranean reservoir. Optionally, the pH of the fluid mixture may be from 0.1 pH unit less than the pH of the brine in the subterranean reservoir to 5.0 pH unit less than the pH of the brine in the subterranean reservoir, from 0.1 pH unit to 0.5 pH unit less than the pH of the brine in the subterranean reservoir, from 0.5 pH unit to 1.0 pH unit less than the pH of the brine in the subterranean reservoir, from 1.0 pH unit to 1.5 pH unit less than the pH of the brine in the subterranean reservoir, from 1.5 pH unit to 2.0 pH unit less than the pH of the brine in the subterranean reservoir, from 2.0 pH unit to 2.5 pH unit less than the pH of the brine in the subterranean reservoir, from 2.5 pH unit to 3.0 pH unit less than the pH of the brine in the subterranean reservoir, from 3.0 pH unit to 3.5 pH unit less than the pH of the brine in the subterranean reservoir, from 3.5 pH unit to 4.0 pH unit less than the pH of the brine in the subterranean reservoir, from 4.0 pH unit to 4.5 pH unit less than the pH of the brine in the subterranean reservoir, or from 4.5 pH unit to 5.0 pH unit less than the pH of the brine in the subterranean reservoir. In some cases, the pH of the fluid mixture does not substantially modify the overall pH of the brine in the subterranean reservoir. However, the pH of the fluid mixture may be used to modify the pH of the brine in the subterranean reservoir in a locality surrounding the injection well, at least temporarily.

[0015] The methods, systems, and fluid mixtures described herein may be useful with a variety of different subterranean reservoirs. Optionally, the subterranean reservoir comprises one or more rock types including, but not limited to, sandstone, carbonate, or volcanic rock. Optionally, the subterranean reservoir comprises one or more minerals including, but not limited to, quartz, calcite, dolomite, anhydrite, gypsum, feldspar, siderite, zeolites, kaolinite, illite, chlorite, or smectite. Optionally, the subterranean reservoir comprises organic matters, such as kerogen or bitumen. The rock in the subterranean reservoir may have a porosity of less than 1% (e.g., tight and shale formations) or may have a larger porosity (e.g., up to 20% or 30%). The rock in the subterranean reservoir may have a permeability of less than 5 nD or 10 nD or may have a larger permeability, such as up to 5 D or 10 D. The hydrocarbons within the subterranean reservoir that may be produced according to methods described herein may include, but are not limited to, crude oil, tarmat, bitumen, heavy oil, tight oil, shale oil, gas condensate, or any combination of these. Optionally, the recovery factor of the hydrocarbons from the subterranean reservoir is greater by injecting the fluid mixture (containing one or more amino acids) as compared to the recovery factor of the hydrocarbons from the subterranean reservoir without injecting the fluid mixture. For example, by modifying a wettability condition of rock surfaces within the reservoir, the reservoir may be more prone to release the hydrocarbons.

[0016] Optionally, a method of this aspect further comprises placing one or more wells in the subterranean reservoir. In embodiments, injecting the fluid mixture into the subterranean reservoir includes injecting the fluid mixture into one or more of the wells. Optionally, producing the hydrocarbons from the subterranean reservoir includes producing the hydrocarbons from one or more of the wells. In some embodiments, producing the hydrocarbons from the subterranean reservoir includes recovering at least a portion of the fluid mixture injected into the subterranean reservoir. Optionally, brine may be produced from the subterranean reservoir, such as during production of the hydrocarbons from the subterranean reservoir or separate from producing the hydrocarbons from the subterranean reservoir. Optionally, an amino acid is present as, identified as, or observed as a tracer in the brine produced from the subterranean reservoir.

[0017] The present disclosure also provides fluid mixtures, such as fluid mixtures for use in producing hydrocarbons from a subterranean reservoir. An example fluid mixture may comprise produced brine or water from another source, such as seawater, pond water, fresh water, etc., and an amino acid, such as an amino acid that has an isoelectric point (PIAA) less than a pH of brine in the subterranean reservoir. The fluid mixture may optionally further comprise one or more of a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, a nanomaterial, a hydrocarbon, nitrogen, carbon dioxide, or water, such as fresh water, seawater, reservoir connate water, produced water, and/or brine.

[0018] In another aspect, the present disclosure provides methods of preparing fluid mixtures, such as fluid mixtures for using in producing hydrocarbons. An example method of this aspect comprises determining a pH of brine in a subterranean reservoir; identifying an amino acid having an isoelectric point (PIAA) less than the pH of the brine in the subterranean reservoir; and preparing a fluid mixture for use in producing hydrocarbons from the subterranean reservoir, such as a fluid mixture comprising the identified amino acid. Preparing the fluid optionally comprises obtaining produced brine from the subterranean reservoir; and augmenting the produced brine with one or more additives including the amino acid. Methods of this aspect may include further steps to produce hydrocarbons, such as by injecting the fluid mixture into the subterranean reservoir, and producing hydrocarbons from the subterranean reservoir. As noted above, the injected fluid mixture may contact rock surfaces in the subterranean reservoir and modify a wettability character of the rock surfaces to a more water-wet condition.

[0019] Systems are also provided herein, such as systems for producing hydrocarbons from a subterranean reservoir. An example system comprises a source of a fluid mixture, such as a fluid mixture that comprises water and one or more amino acids; an injection system in fluid

communication with the source and the subterranean reservoir; and a hydrocarbon production system in fluid communication with the subterranean reservoir. Advantageously, the fluid mixture may comprise any of the fluid mixtures described herein, such as where the one or more amino acids have an isoelectric point (PIAA) less than a pH of brine in the subterranean reservoir.

[0020] Without wishing to be bound by any particular theory, there can be discussion herein of beliefs or understandings of underlying principles relating to the invention. It is recognized that regardless of the ultimate correctness of any mechanistic explanation or hypothesis, an

embodiment of the invention can nonetheless be operative and useful.

BRIEF DESCRIPTION OF THE DRAWINGS

[0021] FIG. 1 provides a schematic illustration of a subterranean reservoir and a system for producing hydrocarbons from the subterranean reservoir.

[0022] FIG. 2 provides an overview of an example hydrocarbon production method.

[0023] FIG. 3 provides the chemical structure of the cation, zwitterion (neutral), and anion forms of glycine and b-alanine and pKa and pi values at room temperature, 298 K.

[0024] FIG. 4 provides a photograph of an imbibition cell and a schematic illustration depicting its dimensions.

[0025] FIG. 5 provides a schematic illustration of an experimental setup saturating a core with reservoir brine and oil.

[0026] FIG. 6 provides photographs showing contact angle change over time for different DI water pHs.

[0027] FIG. 7 provides photographs showing contact angle change over time for different glycine solution pHs.

[0028] FIG. 8 provides photographs showing contact angle change over time for different b- alanine solution pHs.

[0029] FIG. 9 provides data showing contact angles for different solutions as a function of pH. [0030] FIG. 10 provides photographs showing contact angle change over time for formation brine.

[0031] FIG. 11 provides photographs showing contact angle change over time different brines.

[0032] FIG. 12 provides a plot showing contact angle measurements for different brines.

[0033] FIG. 13 provides photographs showing crude oil contact angle change over time for glycine solutions in formation brine.

[0034] FIG. 14 provides a plot showing contact angle measurements for glycine solutions in formation brine.

[0035] FIG. 15 provides photographs showing a crude oil contact angle change over time for b- alanine solutions in formation brine.

[0036] FIG. 16 provides a plot showing contact angle measurements for b-alanine solutions.

[0037] FIG. 17 provides a plot showing a summary of contact angle results.

[0038] FIG. 18 provides data showing oil recovery as a function of time.

[0039] FIG. 19 A, FIG. 19B, FIG. 19C, and FIG. 19D provide data showing oil recovery curves from forced displacement experiments in terms of the original oil in place.

[0040] FIG. 20 provides data showing oil recovery as a function the square root of

dimensionless time.

[0041] FIG. 21 provides a plot showing oil recovery using a brine solution followed by a brine solution including glycine.

[0042] FIG. 22 provides data showing calculated distribution of glycine’s species (zwitterion, anion and cation) in pure water (continuous line) and brine.

[0043] FIG. 23 provides data showing Amott indices as a function of initial solution pH at room temperature.

[0044] FIG. 24 provides photographs showing droplets of oil on Wolfcamp shale surfaces in formation brine at 95 °C at two different times.

[0045] FIG. 25 provides photographs showing droplets of oil on Wolfcamp shale surfaces in 5 wt. % glycine in formation brine at 95 °C at two different times. [0046] FIG. 26 provides photographs showing droplets of oil on Eagle Ford shale surfaces in formation brine at 95 °C at two different times.

[0047] FIG. 27 provides photographs showing droplets of oil on Eagle Ford shale surfaces in 5 wt. % glycine in formation brine at 95 °C at two different times.

[0048] FIG. 28 provides photographs showing surfaces of Wolfcamp shale kept in formation brine (relatively dark) and 5 wt. % glycine in formation brine (relatively light color zones) after 3 days at 95 °C.

[0049] FIG. 29 provides photographs showing surfaces of Eagle Ford shale kept in formation brine (relatively dark) and 5 wt. % glycine in formation brine (relatively light color zones) after 3 days at 95 °C.

[0050] FIG. 30 provides a plot showing contact angles measured for oil droplets on Wolfcamp and Eagle Ford surfaces at 95°C in formation brine and in 5 wt% glycine in the formation brine.

DETAILED DESCRIPTION

[0051] Described herein are methods, systems, compositions, and techniques relating to producing hydrocarbons from subterranean reservoirs and, particularly, involving aqueous mixtures comprising one or more amino acids. As used herein, an“amino acid” refers to a molecule containing amine (-NFh or, generically, -NR'R²) and carboxyl (-COOH) functional groups. Different amino acids have different side chains and positioning of the amine

functionality with respect to the carboxyl group.

[0052] Use of amino acids may be beneficial for a number of reasons. For example, the amino acids may be used as tracers to track fluid movement within the subterranean reservoir, such as to identify which wells within the reservoir fluidly communicate with one another. The amino acids may also advantageously modify conditions within the reservoir to allow for increased or easier production of hydrocarbons from the reservoir, such as by modifying wettability of the rock surfaces within the reservoir. Specifically, amino acids having an isoelectric point (pi) less than a pH of brine or an aqueous fluid within the reservoir may be used. As used herein, an isoelectric point refers to that pH at which the amino acid is neither positively charged (e.g., by adding a proton to the amine group to form an ammonium group) or negatively charged (e.g., by removing a proton from the carboxyl group to form a carboxylate group). The isoelectric point may be equal to the arithmetic average of the pKa of the carboxylic acid group and the pKa of the protonated ammonium group. [0053] The amino acids may advantageously be used in combination with other additives to the fluid mixture injected into the reservoir, such as surfactants, acids, bases, polymers, chelating agents, nanomaterials, solvents, hydrocarbons, or dissolved gases. In some cases, the use of amino acids may allow for lower amounts of other components to be used to the same effect, such as lower amounts of surfactants, as the amino acids may provide a similar effect as the surfactant - namely allowing easier release of the hydrocarbons from pores within the rock in the subterranean reservoir.

[0054] In particular, when the amino acid’s isoelectric point is lower than a pH of brine or an aqueous fluid in the reservoir, the wettability character of the rock surface in the reservoir can change from a more oil-wetting character (less water-wetting) to a more water-wetting character (less oil-wetting). Such an effect can be quantified as a change in contact angle between the rock surface and the aqueous and oleic phases. In embodiments, the rock can have a more oil-wetting character (oil contact angle less than 90°, water contact angle more than 90°) before contact with the amino acid containing fluid mixture and change to a more water-wetting character (water contact angle less than 90°, oil contact angle more than 90°) after contact with the amino acid containing mixture.

[0055] FIG. 1 provides a schematic overview of an example reservoir 100 in which a number of wells 105 have been placed. 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. In some cases, wells 105 may be used for a cyclic injection process (e.g., huff and puff or huff-n-puff processes), where a fluid, such as a fluid mixtures described herein containing amino acids, is injected and, after an optional soak period, a production process takes place. In some cases, wells 105 may be used for flooding processes (e.g., waterflooding processes), in which a fluid, such as the fluid mixtures described herein containing amino acids, is injected into a first well and a second well is used to produce the hydrocarbons. Depending on the specific configuration, the same or different wells 105 may be used for both the injection and the production.

[0056] Wells 105 may optionally be used for injecting a slug of a fluid mixture described herein comprising amino acids in a brine followed by injecting a chase fluid. The chase fluid may comprise a brine and other components, such as chelating agents, amines, or inorganic bases. In some cases, the chase fluid may comprise the same brine that is the base of the fluid mixture comprising amino acids or it may be a different brine (e.g., including different ions and or concentrations of ions). Other example components for the chase 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, a hydrocarbon, nitrogen, or carbon dioxide. Chase fluid may be useful for and may include one or more components for reducing retention of the amino acid and/or for desorbing at least some of the amino acid from the fluid mixture that has absorbed to the rock surfaces in the subterranean reservoir. Example chase fluids may include water or brine and one or more of a chelating agent, an amine, or an inorganic base.

[0057] An injection system may be in fluid communication with the wells 105. As illustrated in FIG. 1, the injection system may include conduits and pumping equipment 110, for example. A fluid source 115 may be in fluid communication with the injection system or the injection system may include the fluid source 115. Fluid source 115 may comprise or include to a storage tank, mixing tank, fluid conduits, or the like, for example, and may be used to provide a fluid mixture for injection into reservoir 100 via wells 105.

[0058] A production system may be in fluid communication with the wells 105. As illustrated in FIG. 1, the production system may include conduits and pumping equipment 120, for example. A storage tank 125 may be in fluid communication with and/or a component of the production system.

[0059] FIG. 2 provides an overview of an example method 200 for producing hydrocarbons from a subterranean reservoir. At block 205, one or more wells are placed in the subterranean reservoir. As noted above, the one or more wells may be independently used for injection of fluid into the subterranean reservoir and/or production of hydrocarbons from the subterranean reservoir. The wells may have any suitable dimensions, orientations, directions, etc. The one or more wells may comprise vertical wells, horizontal wells, or combinations thereof, for example. The wells may optionally be used to produce hydrocarbons or aqueous fluid directly after they are placed in the subterranean reservoir.

[0060] At block 210, the pH of the aqueous fluid (e.g., brine) in the subterranean reservoir is determined. The pH may indicate whether and what amino acids may be useful for aiding the production of the hydrocarbons, as the more desirable amino acids to use may include those having an isoelectric point less than a pH of the aqueous fluid. At block 215, the amino acids to include in an injected fluid mixture are identified based on the pH of the reservoir. In some cases, a low pH in the reservoir may indicate that certain amino acids may not be useful for changing the wettability character of rock surfaces in the subterranean reservoir to a more water wet condition, such as amino acids having an isoelectric point higher than the pH. Depending on the type of rock and minerals within the reservoir, a low pH of the aqueous fluid may also indicate that the rock surfaces already have a water wet character, such as if the pH is lower than the point of zero charge of the rock.

[0061] At block 220, the fluid mixture including the amino acid is prepared, such as by obtaining an aqueous fluid (e.g., brine previously produced from the reservoir or from another reservoir, or seawater, freshwater, aquifer water, etc.) and augmenting the aqueous fluid with the one or more amino acids and any other additives to include (solvents, surfactants, etc.). Without limitation, the fluid mixture may comprise fresh water, seawater, reservoir connate water, produced water, or brine in addition to the amino acids. The fluid mixture may comprise a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, a nanomaterial, a hydrocarbon, nitrogen, or carbon dioxide in addition to the amino acids.

[0062] At block 225, the fluid mixture comprising one or more amino acids is injected into the subterranean reservoir, such as via the one or more wells. The fluid mixture may be continuously injected or may be injected semi-continuously or in one or more discrete injection processes. The injection of the fluid mixture may be proceeded or followed by injection of other fluids, which may or may not include the one or more amino acids, such as a chase fluid.

[0063] At block 230, hydrocarbons are produced from the subterranean reservoir. Depending on the subterranean reservoir and/or configuration, the pressure within the subterranean reservoir may be sufficient to directly produce the hydrocarbons from the subterranean reservoir without requiring an artificial lift to draw the hydrocarbons up to the surface, but in some cases an artificial lifting system may be used. Depending on the production process employed, the injection of the fluid mixture and production of hydrocarbon steps at blocks 225 and 230 may be repeated one or more times, such as in a cyclic injection process.

[0064] At block 230, aqueous fluid may optionally be recovered from the subterranean reservoir. In some cases, it may be desirable to recover at least a portion of the fluid in order to recover some of the one or more amino acids or other additives in the fluid mixture injected into the

subterranean reservoir. Depending on the formation, however, recovery of these components may be feasible or infeasible. It will be appreciated that fluid recovery may occur during or after production of hydrocarbons, for example.

[0065] At block 235, the fluid mixture may optionally be modified so that a different fluid mixture can be injected in a repeated injection step corresponding to block 225. For example, the production of hydrocarbons and/or aqueous fluids from the subterranean reservoir may provide information that is used to change the fluid mixture, such as to use different amino acids, change the amino acid concentration, provide other or more or less additives (e.g., surfactants, acids, bases, etc.) in the fluid mixture. In this way, the injection and production can be tailored based on real time feedback obtained during the production process.

[0066] The invention may be further understood by the following non-limiting examples.

EXAMPLE 1 : AMINO ACIDS AS WETTABILITY MODIFIERS FOR ENHANCED

WATERFLOODING IN CARBONATE RESERVOIRS

[0067] Reservoir wettability plays an important role in waterflooding especially in fractured carbonate reservoirs. In these reservoirs oil recovery from the rock matrix may be inefficient because of the mixed wettability characteristics. This example describes use of amino acids as wettability modifiers that increase waterflooding recovery in carbonate reservoirs.

[0068] All experiments described in this example used a heavy-oil sample taken from a Saudi Arabian carbonate reservoir. Two amino acids were tested, glycine and b-alanine. The amino acids tested in this example are non-toxic and commercially available at relatively low cost.

Contact angle experiments with oil-aged calcite were performed at room temperature with deionized water, and then at 368 K with three saline solutions: 243,571-mg/L salinity formation brine (FB), 68,975-mg/L salinity injection brine 1 (IB 1), and 6,898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB 1.

[0069] The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, compared to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the b-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.

[0070] Glycine was further studied in spontaneous and forced imbibition experiments with oil- aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.

[0071] Results indicated that the enhancement of oil recovery by glycine was more significant with more saline brines (FB and IB 1) than with IB2. It is possible that the glycine pi was decreased at the higher salinities, which increased the anionic form of glycine molecules at a given range of brine pHs. Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. Without wishing to be bound by any theory, one mechanism may be that the glycine solution weakens the interaction between polar oil components and positively-charged rock surfaces when the solution pH is between the glycine pi and the surface’s point of zero charge (pzc). Another mechanism may be that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.

[0072] The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pi, solution’s pH, and rock’s pzc.

[0073] The efficiency of waterflooding depends significantly on the rock wettability in fractured carbonate reservoirs, which often are mixed- or oil-wet. Ultimate oil recovery is usually very small since water cannot imbibe spontaneously into the rock matrix. A change of wettability towards a water-wet state can result in a shift of capillary pressure, changing the capillary pressure from a barrier to a driving force. Therefore, wettability alteration is useful for increasing oil recovery from oil-wet carbonate reservoirs.

[0074] The rock wettability can be determined by the interactions among crude oil, brine, and rock minerals. In conventional oil reservoirs, the rock surfaces are initially wet by formation brine before oil migration. After the displacement of formation brine by oil, the brine still wets the rock surfaces as long as the brine film remains stable. If the brine film becomes unstable, however, the oil contacts the rock surfaces. Then, surface-active oil components are adsorbed on the surfaces, making them less water-wet or even oil-wet. The reversal of the reservoir wettability from oil-wet to water-wet can be achieved by increasing the stability of the thin brine film and/or removing the adsorbed polar components from the rock surfaces.

[0075] Low-salinity waterflooding has been studied as a method of altering the reservoir rock wettability for enhanced oil recovery in carbonate and sandstone reservoirs. One explanation of low-salinity waterflooding in carbonate reservoirs is that low-salinity water can change the wettability of carbonate rocks by altering the overall charge of the rock surfaces and expanding the electrical double layer of the oil/brine and brine/rock interface. Multivalent ions (Ca²⁺, CO3^2', Mg²⁺, and SO4^2') may be the potential determining ions that govern the overall charge of carbonate rock surfaces.

[0076] The impact of seawater on the oil recovery from carbonate reservoirs has been evaluated, where spontaneous imbibition experiments with seawater indicated that the presence of sulfate ion was responsible for the wettability alteration by displacing carboxylic acids from carbonate surfaces. Calcium and magnesium ions were also found to help sulfate ions cause the wettability alteration.

[0077] The application of low salinity waterflooding has also been evaluated through coreflooding experiments in carbonate media. Results showed an increased oil recovery of 18% by the sequential injection of seawater and its dilutions. The impact of individual ions in brine on the wettability alteration of carbonate rocks has also been studied through surface potential experiments. Sulfate and calcium ions were identified as major-potential determining ions that changed the wettability of carbonate rocks by decreasing the surface charge to negative values. In combination with the negatively charged crude oil/brine interface, the negatively charged surfaces increased the stability of the water film that promoted a water-wet state.

[0078] Calcite dissolution has also been proposed as the mechanism for wettability alteration of carbonate rocks, and matching of an aqueous and surface complexation model to imbibition experimental results was attempted. The change of surface potential could not entirely explain the increase in oil recovery. Calcite dissolution was identified as a mechanism for wettability alteration by removal of adsorbed polar oil components.

[0079] Other experiments on the effect of low-salinity water on carbonate rocks indicated that the expansion of the electrostatic double layer caused a short-term effect (around 15 min) on the surface wettability. Mineral dissolution and reprecipitation was shown to cause some surface roughness slowly (more than 12 hr) and was observed by scanning electron microscope imaging.

[0080] The ionic interactions for low-salinity waterflooding set the tone for the present example of using amino acids for wettability alteration of carbonate rocks. Amino acids are non-toxic and biodegradable compounds with two key functional groups, the carboxyl (-COOH) and amino groups (-NH2) within the same molecule. If these two functional groups are attached to the same carbon atom, the molecule is called an a-amino acid. b-Amino acids have an additional methylene group between these two functional groups. The current example is focused on glycine (an a- amino acid), the simplest amino acid, and b-alanine (a b-amino acid). These amino acids were selected because of their low cost and high aqueous solubility. FIG. 3 shows the structures of glycine and b-alanine.

[0081] An important property of amino acids is that their overall charge depends on the solution pH. The amino acid’s isoelectric point (pi) is the pH value at which the amino acid is electrically neutral in the solution. If the solution pH is higher than the pi, the amino acid is negatively charged overall. Otherwise, the amino acid is overall positively charged. This is caused by deprotonation (release of H⁺) of the carboxyl group and ammonium group as the pH increases. The pi of amino acids with neutral side chains, like glycine and b-alanine, can be calculated directly by taking the arithmetic average of their two pKa values (pKa is the negative base- 10 logarithm of the acid dissociation constant Ka). Glycine’s and b-alanine pi values are 5.97 and 6.89 at room temperature, respectively.

[0082] The usefulness of amino acids as wettability alteration agents may arise from the electrostatic interaction between their anionic form with the positively charged calcite surface. Glycine and b-alanine were selected because their pis are lower than usual pH values of reservoir and injection brines. Surfactants synthesized from amino acids were studied for chemical enhanced oil recovery applications and for other industries.

[0083] Materials and Methods. A dead crude oil sample from a carbonate reservoir was used for the experiments described in this Example. Table 1 summarizes properties of the oil sample. The current reservoir pressure and temperature are 26.75 MPa and 372 K, respectively.

[0084] Table 1 : SARA analysis, acid number and viscosity of the crude oil used for contact angle and imbibition experiments. SARA stands for saturations, aromatics, resins, and

asphaltenes.

[0085] The formation brine (FB) has a salinity of 243,571 mg/L. The injection water for waterflooding is made by mixing two brines, injection brine 1 (IB 1) (68,975 mg/L) and injection brine 2 (IB2) (6,898 mg/L). IB2 is made by a 10-fold dilution of IBl with deionized (DI) water. In the lab experiment, these brines were prepared in a step-wise manner to make the ionic compositions given in Table 2. To make one liter of brine, for example, the corresponding amounts of NaCl, CaCh and MgCh salts were dissolved in 700 ml of DI, while the Na2SC>4 and NaHCCb salts were dissolved in 200 ml. After stirring for five minutes, both solutions were mixed, and an appropriate amount of DI water was added for the total volume of one liter.

[0086] Table 2: Ionic compositions and salinities of the three brines used in this Example.

[0087] Glycine and b-alanine samples had a purity greater than 99%. Their molecular structures are shown in FIG. 3. The pi value is 5.97 for glycine and 6.89 for b-alanine at room temperature, 298 K. The aqueous stability was confirmed for all amino acid solutions used in this Example at their corresponding experimental conditions (temperature, brine composition, and pH).

[0088] This Example presents two types of experiments: contact angle and imbibition

(spontaneous and forced). They are described below.

[0089] Contact Angle Experiments. The contact angle experiments were performed by using polished flat pieces of outcrop calcite (Iceland spar). The calcite pieces of approximate dimensions of 5 x 3 ^c 1 cm³ were cut from a calcite block and polished using a diamond grinder. The calcite pieces were aged for one day in FB (Table 2), and then in the crude oil (Table 1) for at least three weeks at 368 K. This temperature was somewhat less than the reservoir temperature, 372 K, to avoid excessive water evaporation and for safety. After the aging, the calcite pieces were retrieved, and any excess oil was carefully removed from the surface.

[0090] The first set of contact angle experiments was focused on the effect of amino acid on the contact angle between oil and water on the oil-aged calcite surface by using DI water with different initial pH values between 3.0 and 10.5; i.e., no brine was used. The solution pH was adjusted for this experiment by adding HC1 and NaOH solutions. This experiment was performed at room temperature since the amino acids’ pis (5.97 for glycine and 6.89 for b-alanine) and calcite’s point of zero charge (pzc) have been reported at room conditions. The reported values of calcite’s pzc vary from 6.5 to 10.8 depending on the type of calcite, the experimental method, equilibration time, background electrolyte and CO2 partial pressure. For this Example, it is reasonable to assume the calcite pzc is 8.8 based on the zeta potential measurements with Iceland Spar in equilibrium with air (360 ppm CO2) at 1.0 bar and room temperature.

[0091] The second set of contact angle experiments was concerned with the effect of amino acid on the contact angle for practical brine compositions at 368 K. Table 2 gives the three brine compositions tested for this contact angle experiment. An appropriate amount of amino acid (glycine or b-alanine) was added to the corresponding brine. All aqueous solutions were placed in an oven at 368 K for at least one day to degasify them and avoid the appearance of gas bubbles that may affect the experiment. Table 3 summarizes the solutions tested in these contact angle experiments.

[0092] Table 3 : Summary of the solutions tested in contact angle experiments. The first three rows correspond to the first set of experiments performed at room temperature, 298 K, with DI water at different pH values. The solutions presented from row 4 to 7 correspond to the second set of experiments with the brines (Table 2) at 368 K. [0093] Each calcite piece was placed inside a glass chamber with the solution to be tested.

Then, five to six oil droplets (depending on the surface area available) were placed on the upper surface of the calcite piece by using a 1.0-ml repeating laboratory dispenser set at a delivery volume of 20 pL. The test chambers were tightly closed. For the second set of experiments, the chambers were placed into the oven at 368 K. For the other experiment, they were kept at room temperature. Pictures of the oil droplets were taken after the initialization and every 24 hours afterward for up to four days. The contact angles of both sides of each oil droplet were measured using onscreen protractor software. An average contact angle from all the droplets was reported for each solution tested.

[0094] Spontaneous Imbibition. A spontaneous imbibition experiment was performed to quantify the effect of amino acid on oil recovery solely by water imbibition. The imbibition cell and its dimensions are shown in FIG. 4. The neck of the cell is graduated to measure the amount of recovered oil.

[0095] Indiana limestone core plugs of 25.4 mm diameter and 127 mm length were used for the spontaneous and forced imbibition experiments in this research. X-ray-diffraction analysis indicates that the Indiana limestone mineralogy is predominantly calcite: 0.9 wt% quartz, 97.7 wt% calcite, 0.2 wt% dolomite, 0.6 wt % halite, and 0.6 wt% illite and mica.

[0096] The porosity and permeability of each core plug were measured with FB (Table 2) and then saturated with the crude oil (Table 1). FIG. 5 is a schematic of the coreflooding system used for saturating the cores. It includes two accumulators for the formation brine and crude oil, a pump, a Hassler type core-holder, a vacuum pump, a hydraulic manual pump to maintain the overburden pressure, pressure gauges, a differential pressure gauge, and an oven.

[0097] The porosity and permeability measurements started by saturating the core plug with FB after evacuation. The effective porosity was determined by subtracting the system’s dead volume (3.0 cm³) from the volume injected. Then, FB was injected at the flow rates of 5, 10, 20, and 30 cmVhour to determine the permeability from the measured differential pressure. A stable pressure difference was recorded after waiting for 5 - 30 minutes for each flow rate.

[0098] After that, the system was heated to 323 K to decrease the oil viscosity. The oil was injected at a constant flow rate of 2.0 cmVhour and, after oil breakthrough, the injection rate was gradually increased to 20 cm³/hour to minimize the capillary end effect. The crude oil injection was continued until the water cut became unmeasurable at the terminal injection rate of 20 cm³/hour. The residual water saturation was estimated from the produced brine volume. Table 4 summarizes the measured porosity, permeability and residual water saturation for each core plug. The results indicate a high level of core-scale heterogeneity. Finally, the oil-saturated cores were placed in a container filled with the crude oil for at least three weeks at 368 K.

[0099] Table 4: Basic petrophysical properties for the Indiana limestone core plugs used in the imbibition experiments.

[0100] The four cores prepared (Table 4) were used for imbibition experiments with the following aqueous solutions: Injection brine 2 (IB2), 5.0 wt% glycine in injection brine 1 (P31- Gly5), 5.0 wt% glycine in injection brine 2 (IB2-Gly5), and 5.0 wt% glycine in formation brine (FB-Gly5). IB2 was chosen as the base case with no amino acid because a large number of publications on low-salinity waterflooding indicates that IB2 should yield greater oil recovery from a carbonate core than IB1 because its salinity was 10 times smaller than that of IB1. The aqueous solutions were prepared one day before the experiment and placed in an oven at 368 K to minimize the amount of dissolved gas. Excess oil was carefully removed from the core plug surfaces before they were placed inside the imbibition cells. Then, the corresponding solution was carefully poured into the cell. This was done without cooling the solutions and inside a heated oven to minimize any oil recovery caused by thermal expansion of fluids. Oil recovery was periodically monitored during the imbibition experiments at 368 K. Table 5 summarizes the solutions tested and the corresponding core plugs.

[0101] Table 5: Solutions tested in the spontaneous imbibition experiment at 368 K. The reported pH values correspond to the initial condition before setting up the experiment. The last column indicates the core plugs given in Table 4.

[0102] Finally, the glycine concentrations in the aqueous phase in the Amott cell after the spontaneous imbibition experiments were quantified by proton nuclear magnetic resonance spectroscopy ( ¹ H NMR). The quantification method consisted of obtaining a 3-gram sample and adding 100 pL of acetone as an internal standard. Then, the solution was thoroughly mixed before ¾ NMR was taken. The concentration of glycine was calculated based on the amount of acetone added and the ratio of the integration values of the peaks of glycine molecule’s methylene protons (2H) and the acetone molecule’s methyl group protons (6H).

[0103] Forced Imbibition. Forced imbibition was performed after the spontaneous imbibition for each core at 368 K. Results were used to calculate the Amott index to water,

where V_{0 SI} and V_{0 FD} are the volume of oil recovered by the spontaneous and forced imbibition, respectively. The forced imbibition was done at a constant-flow rate using the experimental set up used for saturating the cores (Figure 3).

[0104] The injection rates for all forced imbibition tests were initially set for a capillary number of approximately 2 x 10^'5. The capillary number, Nvc, is

where v is the interstitial velocity, p_w is the viscosity of water, k_rw is the end-point relative permeability for water, s is the oil/water interfacial tension, and Q is the oil/water contact angle. It was assumed that k_rWa cos Q = 1 mN /m, a typical value for strongly water-wet media.

[0105] After no oil production was observed for at least two pore volumes, the injection rate was increased to reduce the capillary end effect by achieving the Rapoport and Leas number (NRL) of approximately 3 cp-cm²/min. This is a useful value used to reduce the capillary end effect in corefloods. NRL is defined as

where u is the superficial velocity in cm/min, L is the core length in cm and m is injected fluid viscosity in cp. Table 7 summarizes the initial low injection rate and high injection rate, along with their corresponding capillary number, Nvc, and the Rapoport and Leas number, NRL. [0106] Experimental Results. Below are results of the contact angle and imbibition experiments. There are two sets of contact angle experiments: one with DI water with/without amino acid at a variety of initial pH conditions at room temperature, and the other with three brines at 368 K. Results of imbibition experiments are presented and discussed after the contact angle experiments are described.

[0107] Contact Angle Experiment 1. FIG. 3 shows that the overall charge of amino acid solution depends on how close the solution pH is to the amino acid pi. Glycine, for example, exhibits an overall negative charge if pH > 5.97. Given the calcite pzc of approximately 8.8 at the experiment conditions, glycine is expected to enhance wettability alteration when the solution pH is between glycine pi (5.97) and calcite pzc (8.8). This first set of experiments was to investigate this interplay among these three parameters: amino acid pi, calcite pzc, and solution pH.

[0108] FIGs. 6, 7, and 8 show pictures taken right after the initialization and at Day 3 for DI water, 5 wt% glycine in DI water (DI-Gly5), and 5 wt% b-alanine in DI water (DI-Ala5), respectively. As described above, this experiment was performed at room temperature. FIG. 9 shows the measured contact angles. Note that the horizontal axis in this figure indicates the initial pH values when the experiment was set up. The dissolution of calcite by low pH solutions increased their pH. Table 6 summarizes the pH values before the experiment and after 15 days. The changes in pH indicate that the calcite dissolution was significant for the experiments with the two lowest pH values (3.8 and 4.8 for DI-Gly5 and 3.7 and 4.6 for DI-Ala5).

[0109] Table 6: Initial and final pH values of the solutions in the contact angle experiment presented in FIG. 9. The final pH values were measured after 15 days from the start of the experiment, during which the solution was still in contact with the calcite piece.

[0110] Table 7: Rapoport and Leas number and capillary number for the low and high injection rate used in the forced displacement experiment.

[0111] The Di-water case resulted in a non-monotonic trend of average contact angle with respect to the pH. That is, the average contact angle increased from approximately 100° to 150° with decreasing pH from 10.5 to 5.0. This is in line with the reported behavior of the zeta potential of calcite in DI water and the relation between the surface charge and wettability. That is, as the pH is decreased, calcite’ s surface becomes more positively charged and, therefore, more oil-wet. A drastic reduction in contact angle was observed from 150° to 90° when the pH was reduced from 5.0 to 4.0. This may be attributed to the dissolution of calcite, which causes the polar components absorbed on the surface to be released and alters the wettability to less oil-wet. The calcite dissolution with this low-pH solution may expected since decreasing the solution pH below 5.5 significantly increases the calcite dissolution rate.

[0112] The glycine case resulted in systematically lower contact angles in comparison to the DI- water case. The monotonic reduction of average contact angle with decreasing pH made the contact angle reduction by glycine more pronounced between 5.0 and 9.0 in the initial pH. Note that this pH range reasonably matches the pi of glycine and the pzc of calcite, as explained above. For the initial pH of 3.8, the wettability alteration occurred by at least two mechanisms: calcite dissolution and glycine adsorption.

[0113] The b-alanine case gave similar results to the glycine case, but the contact angle values were approximately 20° greater than the glycine case. This is likely because the pi of b-alanine is greater than that of glycine, which makes the pH range between amino acid pi and calcite pzc smaller with b-alanine. We were unable to obtain data for b-alanine at the initial pH value of 3.7. It appeared that rapid calcite dissolution made it impossible to place oil droplets on the surface.

Oil droplets for the b-alanine case with the initial pH of 4.6 were released from the surface by Day 2

[0114] The interaction of amino acid with calcite’ s surface largely explains the observed contact angle reduction when the initial pH was set between the amino acid pi and the calcite pzc. The adsorption of amino acids on calcite surfaces at different pH values can be used to estimate the calcite’ s pzc to be 9.5. The charges of the mineral surfaces and amino acids may be important to molecular adsorption, and that a higher degree of adsorption may be observed when the amino acid pi is low compared to the calcite pzc.

[0115] At initial pH values below 6.0, it is likely that the rapid calcite dissolution was closely coupled with the amino acid interaction with the calcite’ s surface for the observed contact angle reduction. The rate of calcite dissolution at pH values between about 4.5 and 5.5 can be approximated by

R = i [H⁺] ^0,90 (4) where R is the rate of dissolution in mmol/cm²· s, [H⁺] is the activity of hydrogen ion, and ki is the rate constant that corresponds to the following calcite dissolution reaction:

Calcite dissolution yields bicarbonate ions, which in turn are converted into carbon dioxide and hydroxyl ions, as given by

HCO3 ^ C0₂ + OH-, (6) which increases the solution pH.

[0116] Amino acid in the solution tends to suppress the pH increase by the deprotonation of the carboxyl group. In the case of glycine, for example, the reaction given as

tends to prevent the pH increase. This results in a greater amount of calcite dissolution than when the solution does not contain glycine; i.e., the Di-water case.

[0117] Contact Angle Experiment 2. As mentioned above, this second set of contact angle experiments was to quantify the effect of amino acid on the contact angle with three brine compositions at 368 K. Table 2 presents the compositions of FB, IB1 and IB2. Table 3 presents the solutions that were tested.

[0118] FIG. 10 shows the change in contact angle with FB. The initial average contact angle was 114°, which was measured at room temperature. An equilibrium condition at 368 K was reached with an average contact angle of 130°. Results show that the oil-aged calcite surface was oil-wet, and that FB did not affect calcite’ s wettability.

[0119] FIG. 11 shows the contact angles observed for IB 1 and IB2. The initial average contact angle was 100° and 103° for IB 1 and IB2, respectively. For IB 1, the average contact angle gradually increased to 129°. The average contact angle for IB2 increased up to 108° at Day 2, but then decreased to 102°. FIG. 12 shows the measured contact angle for IB1, IB2 and FB. A systematic reduction in contact angle (more water wet) was observed with decreasing salinity as expected from many papers in the area of low-salinity waterflooding.

[0120] FIG. 13 shows the results for FB-Glyl and FB-Gly5. The initial average contact angle for FB-Glyl solution was 140°, and it gradually decreased to 134°. The initial average contact angle with FB-Gly5 solution was 98°, and it drastically decreased to 50°, yielding the calcite surface strongly water-wet. Some of the droplets were detached from the calcite surface as shown in FIG. 13. The measured contact angles of FB-Gly5 and FB-Glyl are compared to FB in FIG. 14.

[0121] FIG. 15 shows the results of FB-Alal and FB-Ala5 solutions. The initial average contact angles for FB-Alal and FB-Ala5 solutions were 108° and 136°, respectively. The FB-Ala5 solution yielded a more oil-wet surface with a final average contact angle of 142°, while FB-Alal solution final average contact angle was 113°. The measured contact angles of FB-Ala5 and FB- Alal are compared to FB in FIG. 16.

[0122] FIG. 17 summarizes the average contact angles for all tested saline solutions. A useful result is the clear reduction in contact angle and the subsequent detachment of oil droplets with FB-Gly5 solution. For the other solutions, the average contact angles were between 100° and 140° (oil-wet), and no clear reduction in contact angle was observed.

[0123] Calcite’ s surface charge depends at least on the brine composition, salinity, and pH. The zeta potential of calcite has been measured by electrophoresis, which shows that calcite may be positively charged for a range of pH values between 6 and 10 in a formation brine with a salinity of 179,855 mg/L. The contact angle results presented above indicate that the calcite piece submerged into FB was positively charged. This is also implied by the pH values for FB, IB1, and IB2 (7.0 - 7.9) as given in Table 3.

[0124] These results indicate that the presence of ionic components in FB might have affected the absorption of glycine and b-alanine on calcite. The impact of salts appeared to be more significant for b-alanine because the b-alanine solutions in FB did not result in a meaningful reduction in contact angle, unlike the b-alanine solutions in DI water described above. Glycine’s pi, 5.97, is clearly lower than the pH values of FB, IB1, and IB2, but b-alanine’s pi, 6.89, is likely too high to make a clear change in contact angle in the saline solutions tested. That is, glycine was dominantly in the anionic form in the solution, which was suitable for interaction with the positively charged calcite surface b-alanine, however, did not have a sufficiently negative charge in the saline solutions tested.

[0125] It was clear that FB-Gly5 was superior to FB-Glyl in altering the wettability of calcite surfaces towards a more water-wet state. This indicates that 1.0 wt% was below a minimum loading of glycine for a meaningful change in wettability in this experiment. There would be more probable collisions of glycine with the calcite surface at a higher concentration, leading to the wettability alteration towards a more water-wet state.

[0126] b-alanine was incapable of changing the wettability of oil-wet calcite surfaces to water- wet likely because of the electrostatic repulsions between the calcite surface and b-alanine molecules that are both positively charged overall. One interesting observation in the contact angle experiment with b-alanine is that FB-Alal has shown a contact angle that is approximately 15° lower than that of FB-Ala5. This can be because the positively charged b-alanine molecules contribute to the total salinity of the solution. Therefore, FB-Ala5 has increased the contact angle in comparison to FB-Alal.

[0127] Spontaneous and Forced Imbibition Experiments. The imbibition experiments were focused on glycine because of the advantage of glycine over b-alanine in the contact angle experiment described above. IB-2 was chosen as the base case with no glycine because low- salinity waterflooding experiments indicate that IB-2 is expected to perform better than IB-1 and FB in oil recovery.

[0128] When the core plugs were immersed in the solutions, no oil recovery was observed. This indicated that the cores were oil-wet after aging at 368 K for 3 weeks. The experiment was concluded on Day 28, after no more oil recovery was observed for 10 days. FIG. 18 shows the oil recovery factors obtained by spontaneous imbibition with four aqueous solutions: injection brine (IB2), injection brine 2 with 5 wt% glycine (IB2-Gly5), injection brine 1 with 5 wt% glycine (IB1- Gly5), and formation brine with 5 wt% glycine (FB-Gly5). The final oil recovery from the spontaneous imbibition was 30.9% with FB-Gly5, 30.0% with IB1-Gly5, 21.7% with IB2-Gly5, and 11.3% with IB2.

[0129] The oil recovery factors in FIG. 18 (particularly the IB2 case) are not smooth because oil droplets from the core surfaces were released discontinuously and because the oil droplets tended to be large for less water-wet cores (e.g., IB2) with the large viscosity of the oil used in this research. Some options for releasing include either shaking the sample or gently brushing the core surface with a strongly oil-wet rod to force the detachment of oil droplets from the surfaces.

However, none of these measures were taken because doing so requires disturbing the

experimental conditions, such as temperature.

[0130] The spontaneous imbibition was followed by forced imbibition for each core. FIGs. 19A, 19B, 19C, and 19D show the resulting oil recovery curves in terms of original oil in place. The ultimate oil volume recovered at the increased injection rate was used to calculate the Amott index to water for each case.

[0131] The results of the spontaneous and forced imbibition experiments are summarized in Table 8. After monitoring the oil recovery by spontaneous imbibition for 28 days, the Amott cells were moved to another oven before the forced imbibition experiments. During this time, there was an additional oil recovery, which was considered as part of spontaneous imbibition for the calculation of the Amott index to water. The resulting Amott index to water is 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This clearly indicates that the solutions with glycine altered the rock wettability to more water-wet state in comparison to IB2.

[0132] Table 8: Cumulative oil recovery for spontaneous imbibition and forced displacement experiments in terms of the original oil in place. The Amott index to water was calculated considering the ultimate oil volume recovered from forced displacement experiment.

[0133] Although the core plugs were taken from the same block, the substantial heterogeneity in Indiana limestone should be taken into account for the interpretation of data from different core plugs. To decouple the impact of different petrophysical properties of the core plugs from the oil recovery performance, the oil recovery factors were plotted using the dimensionless time (td):

where k is the permeability, f is the porosity, L is the core plug length, d is the core diameter, s is the oil/brine interfacial tension, and m₀ and p_w are respectively the oleic and aqueous phase viscosity.

[0134] Moreover, the differences in initial water saturation and residual oil saturation among the cores were taken into account by expressing the oil recovery factor, RF, in terms of recoverable oil,

where V_0, produced is the volume of oil produced. The volume of recoverable oil, V_0, recoverable, is defined as ), recoverable ^— pore(l. S_wj S_or), (10) where Vpore is the rock pore volume, Swi is the initial water saturation, and Sor is the residual oil saturation after forced imbibition.

[0135] Note that the Amott index to water expressed in Equation 1 is the RF calculated for the spontaneous imbibition using Equation 9 because the recoverable oil from Equation 10 is the denominator of Equation 1. FIG. 20 shows the resulting oil recovery plot with respect to the square root of dimensionless time for the spontaneous imbibition experiments. Although the non smooth oil recovery curves make it unclear, the recovery curves generally follow a linear trend before leveling off. This indicates that the oil recovery process was dominated by the capillary driven countercurrent flow. The comparison between the glycine solutions and IB2 in FIG. 20 clearly shows the positive impact of glycine on oil recovery by spontaneous imbibition. It is not clear from FIG. 20 how the brine composition and salinity affect the oil recovery mechanisms with glycine because the curves for FB-Gly5, IB1-Gly5, and IB2-Gly5 are close to one another. [0136] The positive impact of glycine on oil recovery was reconfirmed by flooding the core for the IB2 case with IB2-Gly5 (i.e., tertiary flooding). The forced imbibition with IB2 was performed for a larger PVI than the other cases to ensure that the core’s residual oil to IB2 had been reached (FIG. 19D). FIG. 21 shows the resulting recovery curve from the injection of IB2 followed by IB2-Gly5 at low and high injection rates. The results indicate that the injection of IB2-Gly5 yielded an additional oil recovery of 3.8% at the lower rate. Since the capillary number was reduced from the previous IB2 injection at a higher rate, the incremental oil recovery is attributed to the effect of glycine on wettability. The subsequent injection of IB2-Gly5 at a higher rate resulted in an additional recovery of 2.3%. The injection of IB2-Gly5 after IB2 resulted in a total incremental oil recovery of 6.1%. Note again that this experiment was to reconfirm the wettability alteration by glycine, instead of testing the use of glycine for tertiary flooding.

[0137] Discussion. The results presented in this Example collectively indicate that the addition of glycine to the injection brine can increase oil recovery by wettability alteration in calcite-rich media. This wettability alteration may employ the anionic form of glycine to interact with positively-charged rock surfaces, causing the removal of polar oil components from the surfaces. The interaction of glycine with rock surfaces was confirmed by measuring the glycine

concentration in the brine after the spontaneous imbibition experiments. Results showed the glycine adsorption of 0.23 mg/g-rock for the FB-Gly5 case, 0.27 mg/g-rock for the IB1-Gly5 case, and 0.24 mg/g-rock for the IB2-Gly5 case. These results are within and on the lower side of the surfactant retention measured for surfactant flooding of carbonate rocks, 0.21 - 1.9 mg/g-rock.

[0138] The solution pH should be above glycine’s PI for glycine to interact with positively charged rock surfaces, as discussed above. Although common pi values for glycine have been reported in the literature, they were measured at room conditions in a diluted solution. Glycine’s actual pi is likely different for different brines and at high temperatures (i.e., reservoir

temperature). Unfortunately, experimental data are scarce about the dependence of glycine’s pi on temperature and the solution’s ionic strength.

[0139] A model for glycine speciation in seawater containing Na⁺, K⁺, Ca²⁺, Mg²⁺, CT, and SO4² ions is available. The protonation constants (pK_a) for the amino group and carboxyl group can be estimated in relation to the ionic strength by use of the Debye-Hiickel equation and Pitzer equations. These protonations constants can be used to calculate glycine’s pi, since glycine’s PI is the arithmetic average of the two pKa values.

[0140] FIG. 22 shows the comparison between glycine’s speciation in pure water and in a brine with a salinity of 86 000 mg/L consisting of NaCl 0.25 mol/L and MgCk 0.25 mol/L. It can be observed that the pK_a value of the amino group of glycine in the brine was shifted about one unit of pH in comparison to the pure water case. This indicates that that glycine’s pi decreased due to the combined effect of the increased ionic strength and the interactions between glycine and Na⁺ and Mg²⁺ ions. This type of pi reduction might have caused the oil recovery factor from the imbibition experiment with glycine to increase with increasing salinity. A reduction in the pi causes the population of glycine’s anionic form to increase, leading to more interaction of glycine with positively charged rock surfaces.

[0141] The three glycine solutions (FB-Gly5, IB1-Gly5, and IB2-Gly5) resulted in similar oil recovery factors from the spontaneous imbibition as given in FIG. 20. The small differences among these glycine cases might be related to the solution pH. FIG. 23 shows a negative correlation between the Amott index to water and the initial solution pH measured at room temperature. Glycine has a tendency to lower the solution pH as confirmed by a separate set of experiments with no calcite piece. In the imbibition experiment with glycine, the reduced pH might have lowered the zeta potential of the rock surfaces. This is consistent with a positive correlation between surface zeta potential and solution pH in their zeta potential experiments for limestone in seawater.

[0142] In summary, glycine likely has a direct and indirect impact on rock wettability. The direct impact is that glycine lowers the polar-polar interaction of oil components with positively charged rock surfaces when the solution pH is between the surface pzc and the glycine pi. Under these conditions, the interaction of the anionic form of glycine with the positively charged calcite surface releases oil which was anchored by carboxylate groups of the naphthenic acids.

Furthermore, the indirect impact is that glycine slightly lowers the solution pH, which in turn lowers the zeta potential of rock surfaces. Although this indirect impact is considered to be a minor factor, it may also contribute to the wettability alteration for increasing oil recovery.

[0143] This example presented an experimental investigation of amino acids as additives to brine for improved waterflooding in carbonate reservoirs. The amino acids tested in this example are glycine and b-alanine. The contact angle experiments with polished calcite pieces

demonstrated that glycine was superior to b-alanine as a wettability modifier in brine. Glycine was further tested in the imbibition experiments (spontaneous and forced) to confirm the increase in oil recovery by wettability alteration from oil-aged limestone cores. Conclusions are as follows.

[0144] The contact angle experiment with DI water at room temperature confirmed that glycine can alter the wettability of oil-aged calcite from oil-wet to strongly water-wet when the solution pH is between the glycine pi (5.97) and the calcite pzc (8.8). The wettability alteration was also confirmed at pH values lower than the glycine pi, and this was attributed to calcite dissolution.

The calcite dissolution at low pH values can be enhanced by the presence of glycine in the solution because glycine tends to suppress the pH increase by deprotonation of the carboxyl group.

[0145] The pi values of glycine and b-alanine depend on temperature and brine composition.

The contact angle experiments with brines at 368 K (section 3.2) indicated that glycine was effective in lowering the contact angle in brines (pH values between 7.0 - 7.9) as long as a sufficient amount of glycine is available for interaction with the oil-wet surface b-alanine was not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.

[0146] The imbibition experiment with Indiana limestone cores showed that glycine can enhance the oil recovery by spontaneous imbibition. The oil recovery factor by IB2 was 11.3%, but the addition of 5 wt% glycine in IB2 (IB2-Gly5) yielded the oil recovery factor of 21.7% by spontaneous imbibition. The impact of glycine on wettability alteration was also confirmed by the tertiary flooding by IB2-Gly5 after the IB2 flooding, which yielded 6.1% additional oil recovery.

[0147] The recovery factor from spontaneous imbibition based on the recoverable oil for each core was 81.3% for FB-Gly5, 76.4% for IB1-Gly5, 79.2% for IB2-Gly5, and 49.2% for IB2. The recovery factors resulted in the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1- Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates clearly that the addition of glycine to brines can significantly change the rock’s wettability towards a more water-wet state. The results also indicated that the effect of brine salinity and composition might be small on the wettability alteration by glycine.

[0148] Analysis of experimental results indicated two possible mechanisms of glycine to enhance the spontaneous imbibition in oil-aged carbonate rocks. One mechanism is that the glycine solution weakens the interaction between polar oil components and positively-charged rock surfaces when the solution pH is between the glycine pi and the surface pzc. Another mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.

[0149] Glycine was found to be quite stable with the brines tested in this example. Up to 10 wt% loading in FB, IB1, and IB2 did not show any precipitation at 298 K. Glycine is non-toxic, widely used in the food industry, and commercially available at relatively low cost.

[0150] Nomenclature for Example 1

Roman d Core plug diameter, m

L Core plug length, m

k Permeability, m²

k rw End point water relative permeability

ki Calcite dissolution rate constant

Ka Acid dissociation constant

pKa Negative base- 10 log of the acid dissociation constant

R Rate of calcite dissolution, mmol/cm² s

Sor Residual oil saturation, v/v

Swi Initial water saturation, v/v

t Time, s

td Dimensionless time

Greek

Q Oil/water contact angle, degrees

go Oil viscosity, Pa s

gw Water viscosity, Pa· s

s Water/oil interfacial tension, N/m

F Porosity, v/v

Abbreviations

pi Isoelectric point

pzc Point of zero charge

RF Recovery factor

TDS Total dissolved solids

[0151] Figure Captions for Example 1. [0152] FIG. 3: Chemical structure of the cation, zwitterion (neutral) and anion forms of glycine and b-alanine. The pKal and pKa2 values are the negative base- 10 logarithm of the acid dissociation constants of the carboxyl and amino groups, respectively. The isoelectric point, pi, is the pH at which the amino acid is electrically neutral. Glycine and b-alanine’s pi are calculated from the arithmetic average of their corresponding pKal and pKa2 values.

[0153] FIG. 4: Imbibition cell and its dimensions.

[0154] FIG. 5: Schematic of the experimental setup for core saturation with reservoir brine and oil.

[0155] FIG. 6: Initial and final contact angles in the experiment with DI water at different solution pHs.

[0156] FIG. 7: Initial and final contact angles for DI-Gly5 at different solution pHs. The oil droplets at a pH of 3.8 detached on the fourth day as a result of the wettability alteration by glycine.

[0157] FIG. 8: Initial and final contact angles of DI-Ala5 at different solution pHs. The oil droplets from the solution with a pH of 4.6 detached after the second day. For the solution with a pH of 3.7, it was not possible to place oil droplets on the surface, and bubbles were caused by calcite dissolution.

[0158] FIG. 9: Average contact angles on Day 3 for DI water, DI-Ala5 and DI-Gly5 solutions. There is no data for DI-Ala5 solution with initial pH of 3.7 since it was not possible to place oil droplets on the calcite surface. The missing data for DI-Ala 5 solution with initial pH 4.6 is because of the detachment of oil droplets by Day 2. Initial and final pH values for the solutions are summarized in Table 6.

[0159] FIG. 10: Contact angle change with time for formation brine.

[0160] FIG. 11 : Contact angle change with time for injection brine 1 (IB 1) and injection brine 2

(IB 2).

[0161] FIG. 12: Contact angle measurements for formation and injection brines at 368 K.

[0162] FIG. 13: Contact angle change with time of formation brine with 1 wt% (FB-Glyl) and 5 wt% glycine (FB-Gly5). For FB-Gly5 solution, oil droplets started to detach at the third day when the buoyancy force is greater than the adhesion force.

[0163] FIG. 14: Contact angle measurements for glycine in FB solutions at 368 K. [0164] FIG. 15: Crude oil contact angle change with time of formation brine with 1 wt% (FB- Alal) and 5 wt% b-alanine (FB-Ala2).

[0165] FIG. 16: Contact angle measurements for b-alanine in FB solutions at 368 K.

[0166] FIG. 17: Summary of contact angle results with brine solutions at 368 K.

[0167] FIG. 18: Oil recovery factor for the spontaneous imbibition experiments at 368 K.

[0168] FIGs. 19A-19D: Oil recovery curves from forced displacement experiments in terms of the original oil in place; i.e. the initial oil volume before the spontaneous imbibition. The increased oil recovery with the higher flow injection rate indicates the presence of the capillary end effect.

[0169] FIG. 20: Oil recovery factors in terms of the movable oil volume with respect to the squared root of dimensionless time. The oil recovery factors show a linear relation of capillary- driven water imbibition.

[0170] FIG. 21 : Oil recovery curve for IB2 followed by the injection of IB2-Gly5. The addition of 5 wt% glycine to IB2 resulted in an incremental oil recovery of 6.1%. The increased oil recovery at a higher injection rate indicates the presence of the capillary end effect.

[0171] FIG. 22: Calculated distribution of glycine’s species (zwitterion, anion and cation) in DI water (continuous line) and brine (NaCl 0.25 - MgC12 0.25 mol/L) (dashed line). The brine has an ionic strength of 0.85 mol/L and a salinity of 86 000 mg/L. The pKa value of the carboxyl group is the pH value at which the cation (green line) and the zwitterion (dark line) concentrations are equal. The pKa value of the amino group is the pH value at which the anion (orange line) and the zwitterion (dark line) concentration are equal. The pi values were calculated reading the pKa values of the plot in De Stefano et al. (2000), referenced below. This figure is a modification of the original figure from therein.

[0172] FIG. 23 : Amott index to water and the initial solution pH measured at room temperature for each case. The correlation for the glycine solutions indicates that a lower pH resulted in a more water-wet state. However, the pH values are similar among the three cases correlated.

EXAMPLE 2: WETTABILITY ALTERATION OF SHALES BY GLYCINE SOLUTION [0173] Experiments were performed to evaluate the ability of a solution containing an amino acid to modify the wettability character of shale formations, including tight formation. In these experiments, samples of shale discs from Wolfcamp and Eagle Ford outcrops were used. The accessible porosities of Wolfcamp outcrop discs were measured to be smaller than 1% (average 0.39%, max. 0.61%, and minimum 0.10% from 23 measurements).

[0174] The discs of Wolfcamp and Eagle Ford shale outcrops were oil-aged for three months to render the surfaces strongly oil-wet. The oil used for aging the shale surfaces was a crude oil (molecular weight 210 g/mol; saturates 71.6 wt%, aromatics 24.8 wt%, resins 3.4 wt%, and asphaltene (n-pentane insoluble) 0.1 wt%).

[0175] The oil-aged discs were submerged in a formation brine or a 5 wt % glycine in the formation brine at 95 °C. The formation brine had a salinity of 243,571 ppm, with ion concentrations of Na⁺ 70,991 mg/L, Ca²⁺ 19,080 mg/L, Mg²⁺ 2561 mg/L, CT 150,165 mg/L, HCO3- 186 mg/L, and SCU² 588 mg/L.

[0176] Oil droplets were placed on the shale surfaces in formation brine and 5 wt % glycine in formation brine and the contact angles of the oil droplets were measured at day 0 (initial) and at day 3 (final). The oil used for the droplets was a crude oil (molecular weight 314 g/mol; saturates 38.7 wt%, aromatics 33.9 wt%, resins 13.4 wt%, and asphaltene (n-pentane insoluble) 14.0 wt%).

[0177] Table 9 shows that 5% glycine in formation brine is effective in altering the Wolfcamp shale wettability to water-wet. The formation brine by itself did not significantly change the contact angle of the oil droplets on Wolfcamp shale (FIG. 24). However, the glycine solution changed the contact angle drastically from 123.66° to 44.87° within 3 days (FIG. 25).

[0178] Table 9: Summary of contact angle measurements on Wolfcamp shale surfaces in formation brine (243,571 ppm) and in 5 wt % glycine in formation brine at 95 °C.

[0179] Glycine exhibited nearly the same level of wettability alteration on Eagle Ford shale surfaces as on Wolfcamp surfaces. See Table 10. The formation brine by itself did not significantly change the contact angle of the oil droplets on Eagle Ford shale surfaces (FIG. 26). However, the glycine solution made the Eagle Ford shale surfaces strongly water- wet; the contact angle changed from 144.17° to 39.67° within 3 days (FIG. 27).

[0180] Table 10: Summary of contact angle measurements on Eagle Ford shale surfaces in formation brine (243,571 ppm) and in 5 wt % glycine in formation brine at 95 °C.

[0181] As a qualitative analysis, changes to the appearance of the shale disc surfaces were observed over time. All the shale disc surfaces were black before the contact angle experiment start (on day 0). However, there was a clear color difference between the two discs, one in formation brine and the other in 5 wt% glycine in formation brine after 3 days. Both Wolfcamp and Eagle Ford Shale surfaces were appeared to be relatively lighter in color (brownish) after 3 days in glycine solution, in comparison to the ones in reservoir brine after 3 days (FIGs. 28 and 29). The surface color change qualitatively indicates the alteration of surface properties by the 5 wt% glycine solution. FIGs. 28 and 29, respectively, show photographs of the Wolfcamp shale discs and the Eagle Ford shale discs after 3 days at 95 °C in the formation brine or the glycine solution in formation brine.

[0182] FIG. 30 provides a plot showing contact angle measurements for oil droplets on the Wolfcamp (WC) and Eagle Ford (EF) shale surfaces at 95 °C in formation brine (FB) and 5 wt% glycine in formation brine (Gly-FB).

[0183] The data indicate that 5 wt% glycine in reservoir brine at 95 °C is capable of rapidly changing both the Eagle Ford and Wolfcamp shale surfaces to water-wet in 3 days. The effect of glycine on wettability alteration was tested for the first time for different rock surfaces of different mineral compositions. The Wolfcamp shale is rich in quartz and clays, but the Eagle Ford shale is rich in calcite as shown in Table 11.

[0184] Table 11 : Mineral compositions of Wolf Camp and Eagle Ford Rocks.

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STATEMENTS REGARDING INCORPORATION BY REFERENCE AND VARIATIONS

[0220] All references throughout this application, for example patent documents including issued or granted patents or equivalents; patent application publications; and non-patent literature documents or other source material; are hereby incorporated by reference herein in their entireties, as though individually incorporated by reference, to the extent each reference is at least partially not inconsistent with the disclosure in this application (for example, a reference that is partially inconsistent is incorporated by reference except for the partially inconsistent portion of the reference). [0221] All patents and publications mentioned in the specification are indicative of the levels of skill of those skilled in the art to which the invention pertains. References cited herein are incorporated by reference herein in their entirety to indicate the state of the art, in some cases as of their filing date, and it is intended that this information can be employed herein, if needed, to exclude (for example, to disclaim) specific embodiments that are in the prior art. For example, when a compound is claimed, it should be understood that compounds known in the prior art, including certain compounds disclosed in the references disclosed herein (particularly in referenced patent documents), are not intended to be included in the claim.

[0222] When a group of substituents is disclosed herein, it is understood that all individual members of those groups and all subgroups and classes that can be formed using the substituents are disclosed separately. When a Markush group or other grouping is used herein, all individual members of the group and all combinations and subcombinations possible 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 items in a list separated by“and/or” are included in the list; for example “1, 2 and/or 3” is equivalent to“’G or‘2’ or‘3’ or‘1 and T or‘1 and 3’ or‘2 and 3’ or‘1, 2 and

3’”.

[0223] Every formulation or combination of components described or exemplified can be used to practice the invention, unless otherwise stated. Specific names of materials are intended to be exemplary, as it is known that one of ordinary skill in the art can name the same material differently. One of ordinary skill in the art will appreciate that methods, device elements, starting materials, and synthetic methods other than those specifically exemplified can be employed in the practice of the invention without resort 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 this invention. Whenever a range is given in the specification, for example, a temperature range, a time range, or a composition range, all intermediate ranges and subranges, as well as all individual values included in the ranges given are intended to be included in the disclosure.

[0224] As used herein,“comprising” is synonymous with“including,”“containing,” or “characterized by,” and 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 recitation herein of the term“comprising”, particularly in a description of components of a composition or in a description of elements of a device, is understood to encompass those compositions and methods consisting essentially of and consisting of the recited components or elements. The invention illustratively described herein suitably may be practiced in the absence of any element or elements, limitation or limitations which is not specifically disclosed herein.

[0225] The terms and expressions which have been employed are used as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding 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 claimed. Thus, it should be understood that although the present invention has been specifically disclosed by preferred embodiments and optional features, modification and variation of the concepts herein disclosed may be resorted to by those skilled in the art, and that such modifications and variations are considered to be within the scope of this invention as defined by the appended claims.

Claims

WHAT IS CLAIMED IS:

1. A method for producing hydrocarbons, the method comprising:

obtaining a fluid mixture comprising water and an amino acid, wherein the amino acid has an isoelectric point (PIAA) less than a pH of brine in a subterranean reservoir;

injecting the fluid mixture into the subterranean reservoir, wherein the fluid mixture or a component thereof contacts rock surfaces in the subterranean reservoir and increases a water wettability character of the rock surfaces; and

producing hydrocarbons from the subterranean reservoir.

2. The method of claim 1, further comprising:

determining the pH of the brine in the subterranean reservoir; and

determining the amino acid based on the pH of the brine in the subterranean reservoir.

3. The method of claim 1, wherein a concentration of the amino acid is from 0.1 wt. % to 15 wt.%.

4. The method of claim 3, wherein the concentration of the amino acid is within a solubility limit of the amino acid in the fluid mixture at a temperature and a pressure of the subterranean reservoir.

5. The method of claim 1, wherein the fluid mixture comprises a plurality of amino acids, wherien at least one of the plurality of amino acids has an isoelectric point less than the pH of brine in the subterranean reservoir.

6. The method of claim 5, wherein a total concentration of the plurality of amino acids is from 0.1 wt. % to 15 wt.%.

7. The method of claim 1, wherein the amino acid is one or more of alanine, b- alanine, arginine, asparagine, aspartic acid, cysteine, glutamic acid, glutamine, glycine, histidine, isoleucine, leucine, lysine, methionine, phenylalanine, proline, serine, threonine, tryptophan, tyrosine, valine, slenocysteine, or pyrrolysine.

8. The method of claim 1, wherein the amino acid is one or more a-amino acids, b-amino acids, g-amino acids, or d-amino acids.

9. The method of claim 1, wherein obtaining the fluid mixture comprises obtaining an aqueous solution and augmenting the aqueous solution with one or more additives including the amino acid.

10. The method of claim 1, wherein the fluid mixture comprises fresh water, seawater, reservoir connate water, produced water, or brine.

11. The method of claim 1, wherein the fluid 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, a hydrocarbon, nitrogen, or carbon dioxide.

12. The method of claim 11, wherein the surfactant comprises an anionic surfactant, a cationic surfactant, a nonionic surfactant, an amphoteric or zwitterionic surfactant, or any combination of these.

13. The method of claim 11, wherein the solvent comprises a hydrocarbon, a hydrocarbon solvent, an amine, an ether, an alcohol, a ketone, or any combination of these.

14. The method of claim 11, wherein the acid comprises hydrochloric acid or acetic acid.

15. The method of claim 11, wherein the salt comprises 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 of these.

16. The method of claim 1, wherein a salinity of the fluid mixture is greater than or about equal to a salinity of the brine in the subterranean reservoir.

17. The method of claim 1, wherein a salinity of the fluid mixture is less than or about equal to a salinity of the brine in the subterranean reservoir.

18. The method of claim 1, wherein a salinity of the fluid mixture is from about 500 ppm to about 243000 ppm, from about 1000 ppm to about 7000 ppm, from about 7000 ppm to about 15000 ppm, or from about 15000 ppm to about 20000 ppm.

19. The method of claim 1, wherein a salinity of the fluid mixture is less than or about 100% of a salinity of the brine in the subterranean reservoir.

20. The method of claim 1, wherein a pH of the fluid mixture is less than or about equal to the pH of the brine in the subterranean reservoir.

21. The method of claim 1, wherein a rate of producing the hydrocarbons from the subterranean reservoir is greater after injecting the fluid mixture as compared to a rate of producing the hydrocarbons from the subterranean reservoir before injecting the fluid mixture.

22. The method of claim 1, wherein the subterranean reservoir comprises sandstone, carbonate, volcanic rock, or any combination of these.

23. The method of claim 1, wherein the subterranean reservoir comprises one or more minerals including quartz, calcite, carbonate, dolomite, anhydrite, gypsum, feldspar, siderite, zeolites, kaolinite, illite, chlorite, or smectite.

24. The method of claim 1, wherein the subterranean reservoir comprises kerogen and bitumen.

25. The method of claim 1, wherein the hydrocarbons comprise crude oil, tarmat, bitumen, heavy oil, tight oil, shale oil, gas condensate, or any combination of these.

26. The method of claim 1, wherein injecting the fluid mixture into the subterranean reservoir comprises injecting the fluid mixture into the subterranean reservoir as a slug, and wherein the method further comprises injecting a chase fluid into the subterranean reservoir after injecting the fluid mixture into the subterranean reservoir as a slug.

27. The method of claim 26, wherein the chase fluid 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, a hydrocarbon, nitrogen, or carbon dioxide.

28. The method of claim 26, wherein the chase fluid includes water or brine and one or more of a chelating agent, an amine, or an inoganic base.

29. The method of claim 26, wherein the chase fluid includes one or more components for reducing retention of the amino acid and/or for desorbing at least some of the amino acid from the fluid mixture that has absorbed to the rock surfaces in the subterranean reservoir.

30. The method of claim 1, further comprising placing one or more wells in the subterranean reservoir.

31. The method of claim 30, wherein injecting the fluid mixture into the subterranean reservoir includes injecting the fluid mixture into one or more of the wells.

32. The method of claim 30, wherein producing the hydrocarbons from the subterranean reservoir includes producing the hydrocarbons from one or more of the wells.

33. The method of claim 1, wherein producing the hydrocarbons from the subterranean reservoir includes recovering at least a portion of the fluid mixture injected into the subterranean reservoir.

34. The method of claim 1, further comprising producing brine from the subterranean reservoir.

35. The method of claim 34, wherein producing the hydrocarbons from the subterranean reservoir includes producing the brine from the subterranean reservoir.

36. The method of claim 34, wherein the amino acid is present as a tracer in the brine produced from the subterranean reservoir.

37. The method of claim 34, further comprising identifying the amino acid as a tracer in the brine produced from the subterranean reservoir.

38. The method of claim 1, wherein injecting the fluid mixture and producing the hydrocarbons comprises a flooding process or a huff-n-puff process.

39. The method of claim 1, wherein injecting the fluid mixture and producing the hydrocarbons comprises a continuous injection process or a cyclic injection process.

40. A fluid mixture for use in producing hydrocarbons from a subterranean reservoir, the fluid mixture comprising:

produced brine, and

an amino acid, wherein the amino acid has an isoelectric point (PIAA) less than a pH of brine in the subterranean reservoir.

41. The fluid mixture of claim 40, wherein the isoelectric point (PIAA) of the amino acid is less than a point of zero charge (PZCrock) of rock in the subterranean reservoir.

42. The fluid mixture of claim 40, further comprising one or more of a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, a nanomaterial, a hydrocarbon, nitrogen, carbon dioxide, or water.

43. A method comprising:

determining a pH of brine in a subterranean reservoir;

identifying an amino acid having an isoelectric point (PIAA) less than the pH of the brine in the subterranean reservoir; and

preparing a fluid mixture for use in producing hydrocarbons from the subterranean reservoir, wherein preparing the fluid mixture comprises:

obtaining produced brine from the subterranean reservoir; and

augmenting the produced brine with one or more additives including the amino acid.

44. The method of claim 43, further comprising:

injecting the fluid mixture into the subterranean reservoir, wherein the fluid mixture contacts rock surfaces in the subterranean reservoir and modifies a wettability character of the rock surfaces to a more water-wet condition; and

producing hydrocarbons from the subterranean reservoir.

45. A system for producing hydrocarbons from a subterranean reservoir, the system comprising:

a source of a fluid mixture, wherein the fluid mixture comprises water and one or more amino acids;

an injection system in fluid communication with the source and the subterranean reservoir; and

a hydrocarbon production system in fluid communication with the subterranean reservoir.

46. The system of claim 45, wherein the fluid mixture comprises the fluid mixture of any of claims 40-42.

47. The system of claim 45, wherein the fluid mixture is prepared according to the method of claim 43.

48. The method of any of claims 1-37, wherein the fluid mixture comprises the fluid mixture of any of claims 40-42.

49. The method of any of claims 1-37, wherein the fluid mixture is prepared according to the method of claim 43.

50. The fluid mixture of any of claims 40-42, wherein the fluid mixture is prepared according to the method of claim 43.