METHODS FOR HYDROCARBON RECOVERY.

Abstract

This document provides liquid polymer (LP) compositions comprising a synthetic (co)polymer (e.g., an acrylamide (co)polymer), as well as methods for preparing inverted polymer solutions by inverting these LP compositions in an aqueous fluid. The resulting inverted polymer solutions can have a concentration of a synthetic (co)polymer (e.g., an acrylamide (co)polymer) of 50 to 15,000 ppm, and a filtration rate of 1.5 or less at 15 psi (0.10 kg / cm² to 1.05 kg / cm²) using a 1.2 µm filter. Methods for using these inverted polymer solutions in oil and gas operations, including enhanced oil recovery, are also provided.

Description

METHODS FOR HYDROCARBON RECOVERY Background of the Invention Water-soluble polymers such as polyacrylamide and acrylamide copolymers with other monomers are known to exhibit superior thickening properties when dissolved in aqueous media. Anionic carboxamide polymers, such as acrylamide / acrylic acid copolymers, including those prepared by polyacrylamide hydrolysis, are particularly well-known for this purpose. These polymers can be used as fluid mobility control agents in enhanced oil recovery (EOR) processes. In the past, these polymers were commercially available as powders or finely divided solids that were subsequently dissolved in an aqueous medium at the time of use. Because such dissolution steps can be time-consuming and often require fairly expensive mixing equipment, the polymers are sometimes supplied in water-in-oil emulsions where the polymer is dissolved in the dispersed aqueous phase. Water-in-oil emulsions can be inverted to form oil-in-water emulsions at the time of use. Unfortunately, for many applications, existing water-in-oil emulsions are not as easily inverted as desired. Furthermore, inverted emulsions REF: 288849 The resulting emulsions are often unable to pass through porous structures. This significantly limits their usefulness as, for example, fluid mobility control agents in EOR applications. Furthermore, existing water-in-oil emulsions often cannot be effectively inverted using an aqueous medium containing dissolved salts, as is often the case in enhanced oil recovery practices. Summary of the Invention This document provides methods for preparing inverted polymer solutions. The methods for preparing inverted polymer solutions may comprise inverting an LP composition comprising one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) dispersed or emulsified in one or more hydrophobic liquids to provide an inverted polymer solution having a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) of 50 to 15,000 ppm. For example, in some embodiments, methods for preparing inverted polymer solutions may comprise providing a liquid polymer composition (LP) comprising one or more hydrophobic liquids having a boiling point of at least 100°C; at least 39% (e.g., greater than or equal to 39%) by weight of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers); or plus emulsifying surfactants; and one or more inverting surfactants; and inverting the LP composition in an aqueous fluid to provide an inverted polymer solution having a synthetic (co)polymer concentration of 50 to 15,000 ppm (e.g., 500 to 5,000 ppm). In other embodiments, methods for preparing inverted polymer solutions may comprise providing a liquid polymer composition (LP) in the form of an inverted emulsion comprising one or more hydrophobic liquids having a boiling point of at least 100°C; up to 35 wt% of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers); one or more emulsifying surfactants; and one or more inverting surfactants; and invert the LP composition in an aqueous fluid to provide an inverted polymer solution having a synthetic (co)polymer concentration of 50 to 15,000 ppm (e.g., 500 to 5000 ppm).In other embodiments, methods for preparing inverted polymer solutions may comprise providing a liquid polymer composition (LP) in the form of an inverted emulsion comprising one or more hydrophobic liquids having a boiling point of at least 100°C; up to 38% by weight of one or more synthetic copolymers (e.g., one or more acrylamide copolymers); one or more emulsifying surfactants; and one or more inverting surfactants; and inverting the LP composition into an aqueous fluid. Provide an inverted polymer solution that has a synthetic copolymer concentration of 50 to 15,000 ppm (e.g., 500 to 5000 ppm). Inverted polymer solutions may exhibit a filtration rate of 1.5 or less (e.g., a filtration rate of 1.2, a filtration rate of 1.2 or less, and / or a filtration rate of 1.1 to 1.3) at 15 psi (1.05 kg / cm²). 2 ) using a 1.2pm filter. In some embodiments, LP composition inversion comprises a single step. For example, in some cases, LP composition inversion may involve diluting the LP composition in the aqueous fluid in an in-line mixer to provide the inverted polymer solution. The in-line mixer may be a static mixer or a dynamic mixer (e.g., an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump). In certain embodiments, the in-line mixer is positioned on the surface, the underlying surface, below the sea surface, or at the bottom of the well. In other embodiments, LP composition reversal may comprise two or more stages. For example, in some cases, LP composition reversal may comprise, as a first stage, reversing the LP composition in the aqueous fluid in a first in-line mixer to provide a concentrated polymer composition having a concentration of synthetic (co)polymer (for example, one or more (co)polymers of acrylamide) up to 15,000 ppm; and as a second stage, dilute the concentrated polymer composition in the aqueous fluid in a second in-line mixer to provide the inverted polymer solution. The first in-line mixer and the second in-line mixer may each be individually a static mixer or a dynamic mixer (e.g., an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump). In certain embodiments, the second in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well. The procedure for hydrocarbon recovery is also provided herein. Methods for hydrocarbon recovery may include providing an underlying surface reservoir containing hydrocarbons; providing a well in fluid communication with the underlying surface reservoir; preparing an inverted polymer solution according to the methods described herein; and injecting the inverted polymer solution through the well into the underlying surface reservoir. The well in the second stage may be an injection well associated with an injection well, and the method may further include providing a production well located a predetermined distance from the injection well and with a The production well is in fluid communication with the underlying surface reservoir. In these configurations, the injection of the inverted polymer solution can increase the flow of hydrocarbons to the production well. In some configurations, the well in the second stage may be a hydraulic fracturing well that is in fluid communication with the underlying surface reservoir. Brief Description of the Figures Figure 1 is a process flow diagram illustrating a single-step process for preparing an inverted polymer solution. Figure 2 is a process flow diagram illustrating a two-stage process for preparing an inverted polymer solution. Figures 3A and 3B are process flow diagrams illustrating a plurality of processes for preparing inverted polymer solutions. Figure 4 illustrates an in-line injection system that can be used in conjunction with the compositions and procedures described herein. Figure 5 illustrates an alternative in-line injection system that can be used in conjunction with the compositions and procedures described herein. Figure 6 illustrates an in-line injection system alternative that can be used in conjunction with the compositions and procedures described in this document. Figure 7 illustrates an alternative in-line injection system that can be used in conjunction with the compositions and procedures described herein. Figure 8 illustrates an alternative in-line injection system that can be used in conjunction with the compositions and procedures described herein. Figure 9 illustrates an alternative in-line injection system that can be used in conjunction with the compositions and procedures described herein. Figure 10 is a representation of the pressure drop and relative permeability after the injection of an inverted polymer solution into a sandstone core. The constant pressure drop and relative permeability observed after the injection of the inverted polymer solution are consistent with no plugging of the sandstone core. Figure 11 is a representation of the filtration ratio test performed using a 1.2-micron filter for an inverted polymer solution. Inverted polymeric solution (2000 ppm polymer) passes through a 1.2 micron filter with a filtration rate of less than 1.2, showing an improved filtering capacity of the inverted polymeric solution. Figure 12 is a representation of viscosity over a broad shear rate range for an inverted polymer solution (2000 ppm polymer in synthetic brine, measured at 31°C). The viscosity of the inverted polymer solution exhibits typical shear-thinning behavior across the broad shear rate range. The viscosity is measured as 24 cP at 10 s⁻¹ and 31°C. Figure 13 is a representation of viscosity over the broad shear rate range for the clean LP composition activity of the clean LP composition test here is 50% and the LP viscosity is measured at 180 cP at 10 s _1 and 25°C. The low viscosity with high activity makes the LP composition easy to handle in the field. Figure 14 is a representation of the pressure drop and oil recovery for an inverted LP solution (2000 ppm polymer) in an unconsolidated sand pack. Oil recovery increases as inverted LP is injected, while the pressure drop for LP injection shows the steady-state and low values ​​at the end of the experiment. The low steady-state pressure drop The LP at the end of the experiment indicates improved performance since the LP solutions do not clog the core during oil recovery. Figure 15 is a graph showing the viscosity of LP as a function of concentration at a temperature of 31°C and a shear rate of 10 s _1 . Figure 16 is a graph of LP shear viscosities as a function of shear rate at a temperature of 31°C. Figures 17A and 17B are graphs of the filtration ratio tests performed using a 5-micrometer filter (Figure 17A) and a 1.2-micrometer filter (Figure 17B) for the inverted polymer solutions M1-M6. The inverted polymer solution (2000 ppm polymer) passes through a 1.2-micrometer filter with a filtration ratio less than 1.5, demonstrating the filtration capacity of the inverted polymer solution. Figure 18 is a graph of the pressure drop after injection of a polymer solution (2000 ppm) into a sandstone core (1.2 D) with a pressure tap attached 2" from the inlet to monitor front plugging. The constant pressure drop observed after injection of the polymer solution into the entire core and the 1. a The sections of the set are coherent without significant plugging of the sandstone core. The inverted polymer was injected. up to 45 PV followed by immersion in water. The pressure drop during immersion in water also showed that the inversion of the polymer solution did not plug the core. Figure 19A is a graph of the normalized permeability reduction of a conventional inverted liquid polymer LP#1 (2000 ppm) in a sandstone with a pressure tap (3") (7.62 cm) showing frontal plugging at the inlet. Figure 19B is a graph of the normalized permeability reduction of the inverted LP composition (2000 ppm) in a sandstone with a pressure tap (2") (5.08 cm) showing no significant plugging around 250 PV of the injection at the inlet. Figure 20 is a graph of the Permeability Reduction Factor (Rk) and the Normalized Damage Factor, s / ln(r s / r w) based on the filtration ratio at 1.2 pm (FRi.s). Rk and the damage factor were calculated at 25 PV of the injection in the sandstone core. Figure 21 is a bar chart illustrating the viscosity performance achieved by using multi-stage (two) mixing configurations and single-stage mixing configurations with and without a dynamic mixer. Figure 22A is a graph of viscosity performance as a function of pressure drop across the static mixer. Figure 22B is a graph of the filtration ratio as a function of the pressure drop across the static mixer. Detailed description of the invention This document provides liquid polymer (LP) compositions comprising a synthetic polymer, such as an acrylamide (co)polymer, and methods for preparing inverted polymer solutions by inverting these LP compositions in an aqueous fluid. Methods for using these inverted polymer solutions in oil and gas operations, including enhanced oil recovery (EOR), are also provided. The term "enhanced oil recovery" refers to techniques for increasing the amount of unrefined oil (e.g., crude oil) that can be extracted from an oil reservoir (e.g., an oil field). Using EOR, 40–60% of the original oil in the reservoir can typically be recovered, compared to only 20–40% using primary and secondary recovery (e.g., by water injection or natural gas injection). Enhanced oil recovery may also be called improved oil recovery or tertiary oil recovery (as opposed to primary and secondary oil recovery). Examples of EOR operations include, for example, miscible gas injection (which includes, for example, Carbon dioxide injection), chemical injection (sometimes called chemical enhanced oil recovery (CEOR), and which includes, for example, polymer injection, alkali injection, surfactant injection, compliance control operations, as well as combinations thereof, such as polymer-alkali injection or alkali-surfactant-polymer injection), microbial injection, and thermal recovery (which includes, for example, cyclic steam, steam injection, and fire injection). In some embodiments, the EOR operation may include a polymer injection (P) operation, an alkali-polymer injection (AP) operation, a surfactant-polymer injection (SP) operation, an alkali-surfactant-polymer injection (ASP) operation, a compliance control operation, or any combination thereof.The terms "operation" and "application" may be used interchangeably in this document, as in EOR operations or EOR applications. For the purposes of this description, including the claims, the filtration rate (FR) can be determined using a 1.2 micron filter at 15 psi (1.05 kg / cm²). 2 (plus or minus 10% of 15 psi) at room temperature (e.g., 25°C). The 1.2-micron filter can have a diameter of 47 mm or 90 mm, and the filtration rate can be calculated as the ratio of the time it takes to filter 180 to 200 ml of the inverted polymer solution divided by the time for 60 to 80 ml of the inverted polymer solution to filter through. t 200ml — t 180ml _ _____________ ml — t 60 mi For the purposes of this description, including the claims, the inverted polymer solution is required to exhibit an FR of 1.5 or less. The inversion of conventional inverted emulsion polymers can be challenging. For use in many applications, rapid and complete inversion of the inverted emulsion polymer composition is required. For example, many applications require rapid and continuous inversion and dissolution (e.g., complete inversion and dissolution in five minutes or less). For certain applications, including many oil and gas applications, it may be desirable to completely invert and dissolve the emulsion or LP to a final concentration of 500 to 5000 ppm in an online system within a short period of time (e.g., less than five minutes). For certain applications, including many enhanced oil recovery (EOR) applications, it may be desirable for the inverted composition to flow through a hydrocarbon-bearing formation without obstructing it. Formation obstruction can slow or inhibit oil production. This is a particular concern. large in the case of formations containing hydrocarbons that have a relatively low permeability before tertiary oil recovery. A commonly used test to determine the performance of the emulsion or LP under such conditions involves measuring the time it takes for specified volumes / concentrations of solution to flow through a filter, commonly referred to as the filtration quotient or FR (Filtration Rate). For example, U.S. Patent No. 8,383,560 describes a filtration rate test method that measures the time taken for given volumes of a solution containing 1000 ppm of active polymer to flow through a filter. The solution is contained in a cell pressurized to 2 bar, and the filter has a diameter of 47 mm and a pore size of 5 microns. The times required to obtain 100 mL (t100 mi), 200 mL (t200 mi), and 300 mL (t300 mi) of filtrate were measured. These values ​​were used to calculate the FR, expressed by the following formula: *300 mi - *200 771 / FR =-------------- *200 mi - *100 7nZ The FR generally represents the ability of the polymer solution to clog the filter for two consecutive equivalent volumes. Generally, a lower FR indicates improved performance. U.S. Patent No. 8,383,560, which is incorporated here as a reference, explains that A desirable FR using this method is less than 1.5. However, polymer compositions that yield desirable results for this test method have not necessarily provided acceptable performance in the field. In particular, many polymers with a filtration rate (FR) (using a 5-micron filter) below 1.5 exhibit low injectivity; that is, when injected into a formation, they tend to plug the formation, retarding or inhibiting oil production. A modified filtration rate test method using a smaller pore size (i.e., the same filtration rate test method except the previous filter is replaced with one having a diameter of 47 mm and a pore size of 1.2 microns) and lower pressure (15 psi) (1.05 kg / cm²) has proven effective. 2This provides an improved screening method. Inverted polymer solutions prepared by the methods described herein can provide an FR (using a 1.2-micron filter) of 1.5 or less. In field tests, these compositions can exhibit improved injectivity over commercially available polymer compositions—including other polymer compositions with an FR (using a 5-micron filter) of less than 1.5. As such, the inverted compositions described herein are suitable for use in a variety of oil and gas applications, including EOR. LP Compositions LP compositions may comprise one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) dispersed or emulsified in one or more hydrophobic liquids. In some embodiments, LP compositions may further comprise one or more emulsifying surfactants and one or more inverting surfactants. In some embodiments, LP compositions may further comprise a small amount of water. For example, LP compositions may further comprise less than 10% by weight (e.g., less than 5% by weight, less than 4% by weight, less than 3% by weight, less than 2.5% by weight, less than 2% by weight, or less than 1% by weight) of water, based on the total weight of all components of the LP composition. In certain embodiments, LP compositions may be water-free or substantially water-free (i.e., the composition may include less than 0.5% by weight of water, based on the total weight of the composition).LP compositions may optionally include one or more additional components that do not substantially diminish the desired performance or activity of the composition. A person with ordinary skill in the technique will understand how to properly formulate the LP composition to provide the desired or necessary characteristics or properties. In some forms, the LP composition may comprise one or more hydrophobic liquids that have a boiling point of at least 100°C; at least 39% by weight of one or more synthetic copolymers (for example, acrylamide (co)polymers); one or more emulsifying surfactants; and one or more inversion surfactants. In some embodiments, the LP composition may comprise one or more hydrophobic liquids having a boiling point of at least 100°C; at least 3.9 wt% of particles of one or more acrylamide (co)polymers; one or more emulsifying surfactants; and one or more inverting surfactants. In certain embodiments, when the composition is fully inverted in an aqueous fluid, the composition yields an inverted polymer solution having a filtration rate (FR) (1.2-micron filter) of 1.5 or less. In certain embodiments, the inverted polymer solution may comprise 500 to 5000 ppm (e.g., 500 to 3000 ppm) of active polymer and may have a viscosity of at least 20 cP at 30°C. In some forms, LP compositions may comprise less than 10% by weight (e.g., less than 7% by weight, less than 5% by weight, less than 4% by weight, less than 3% by weight, less than 2.5% by weight, less than 2% by weight, or less than 1% by weight) pre-investment water, based on the total weight of all components of the LP composition. In certain forms, the pre-investment LP composition comprises from 1% to 10% water by weight, or from 1% to 5% water by weight, based on the total amount of all components of the composition. In some embodiments, the solution viscosity (SV) of a 0.1% solution of the LP composition may be greater than 3.0 cP, or greater than 5 cP, or greater than 7 cP. The SV of the LP composition may be selected based, at least in part, on the intended active ingredient concentration of the inverted polymer solution, to provide desired performance characteristics in the inverted polymer solution. For example, in certain embodiments where the inverted composition is intended to have an active ingredient concentration of approximately 2000 ppm, it is desirable for the SV of a 0.1% solution of the LP composition to be in the range of 7.0 to 8.6, because at this level, the inverted solution has the desired viscosity and FR1.2 properties.A liquid polymer composition with a lower or higher SV range can still provide desirable results, but may require changing the concentration of active ingredients in the invert composition to achieve the desired viscosity and FR1.2 properties. For example, if the liquid polymer composition has a lower SV range, it may be desirable to increase the concentration of active ingredients in the invert composition. In some embodiments, the LP composition may comprise one or more synthetic (co)polymers (for example, one or more acrylamide (co)polymers) dispersed in one or more hydrophobic liquids. In these embodiments, the LP composition may comprising at least 39% by weight of polymer (e.g., at least 40% by weight, at least 45% by weight, at least 50% by weight, at least 55% by weight, at least 60% by weight, at least 65% by weight, at least 70% by weight, or at least 75% by weight), based on the total amount of all components of the composition. In some embodiments, the LP composition may comprise 80% by weight or less of polymer (e.g., 75% by weight or less, 70% by weight or less, 65% by weight or less, 60% by weight or less, 55% by weight or less, 50% by weight or less, 45% by weight or less, or 40% by weight or less), based on the total amount of all components of the composition. In these embodiments, the LP composition may comprise a quantity of polymer ranging from any of the minimum values ​​described above to any of the maximum values ​​described above. For example, in some embodiments, the LP composition may comprise from 39% to 80% by weight of polymer (e.g., from 39% to 60% by weight of polymer, or from 39% to 50% by weight of polymer), based on the total weight of the composition. In some embodiments, the LP composition may comprise one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) emulsified in one or more hydrophobic liquids. In these embodiments, the LP composition may comprise at least 10% polymer by weight (e.g., at least 15% by weight, at least 20% by weight, at least 25% by weight, or at least 30% by weight), based on the total amount of all components of the composition. In some embodiments, the LP composition may comprise less than 38% by weight of polymer (for example, less than 35% by weight, less than 30% by weight, less than 25% by weight, less than 20% by weight, or less than 15% by weight), based on the total amount of all components of the composition. In these embodiments, the LP composition may comprise a quantity of polymer ranging from any of the minimum values ​​described above to any of the maximum values ​​described above. For example, in some embodiments, the LP composition may comprise from 10% to 38% by weight of polymer (e.g., 10% to 35% by weight of polymer, 15% to 30% by weight of polymer, 15% to 35% by weight of polymer, 15% to 38% by weight of polymer, 20% to 30% by weight of polymer, 20% to 35% by weight of polymer, or 20% to 38% by weight of polymer), based on the total weight of the composition. Hydrophobic liquid In some embodiments, the LP composition may include one or more hydrophobic liquids. In some cases, one or more hydrophobic liquids may be organic hydrophobic liquids. In some embodiments, one or more hydrophobic liquids each have a boiling point of at least 100°C (for example, at least 135°C, or at least 180°C). If the organic liquid has a boiling range, the term "boiling point" refers to the lower limit of the boiling range. In some embodiments, one or more hydrophobic liquids may be aliphatic hydrocarbons, aromatic hydrocarbons, or mixtures thereof. Examples of hydrophobic liquids include, but are not limited to, water-immiscible solvents such as paraffin hydrocarbons, naphthalene hydrocarbons, aromatic hydrocarbons, olefins, oils, stabilizing surfactants, and mixtures thereof. Paraffin hydrocarbons may be saturated, linear, or branched. Examples of suitable aromatic hydrocarbons include, but are not limited to, toluene and xylene. In certain embodiments, the hydrophobic liquid may comprise an oil, for example, a vegetable oil such as soybean oil, rapeseed oil, canola oil, or a combination thereof, and any other oil produced from the seed of any of several varieties of the rapeseed plant. In some forms, the amount of one or more hydrophobic liquids in the invert emulsion or LP composition is 20% to 60%, 25% to 54%, or 35% to 54% by weight, based on the total amount of all components of the LP composition. synthetic (Co)polymers In some forms, the LP composition includes one or more synthetic (co)polymers, such as one or more (co)polymers containing acrylamide. As used herein, the terms "polymer," "polymers," "polymeric," and similar terms are used in their ordinary sense as understood by a person skilled in the art, and may therefore be used herein to describe a large molecule (or group of such molecules) containing repeating units. Polymers can be formed in a variety of ways, including the polymerization of monomers and / or chemical modification of one or more repeating units of a precursor polymer. A polymer may be a "homopolymer" comprising substantially identical repeating units formed by, for example, polymerizing a particular monomer. A polymer may also be a "copolymer" comprising two or more different repeating units formed, for example, by copolymerizing two or more different monomers, and / or by chemically modifying one or more repeating units of a precursor polymer.The term "terpolymer" may be used here to refer to polymers containing three or more different repeating units. The term "polymer" is intended to include both the acidic form of the polymer and its various salts. In some embodiments, one or more synthetic (co)polymers can be a useful polymer for enhanced oil recovery applications. The term "enhanced oil recovery" or "EOR" (also known as enhanced oil recovery) tertiary petroleum), refers to a process for the production of hydrocarbons in which an aqueous injection fluid comprising at least one water-soluble polymer is injected into a hydrocarbon-containing formation. In some embodiments, one or more synthetic (co)polymers comprise water-soluble synthetic (co)polymers.Examples of suitable synthetic acrylic (co)polymers include acrylic polymers such as polyacrylic acids, polyacrylic acid esters, partially hydrolyzed acrylic esters, substituted polyacrylic acids such as polymethacrylic acid and polymethacrylic acid esters, polyacrylamides, partially hydrolyzed polyacrylamides and polyacrylamide derivatives such as acrylamide tertiary butylsulfonic acid (ATBS); copolymers of unsaturated carboxylic acids, such as acrylic acid or methacrylic acid, with derivatives such as ethylene, propylene and butylene and their oxides; polymers of unsaturated dibasic acids and anhydrides such as maleic anhydride; vinyl polymers, such as polyvinyl alcohol (PVA), N-vinylpyrrolidone, and polystyrene sulfonate; and copolymers thereof, such as copolymers of these polymers with monomers such as ethylene, propylene, styrene, methylstyrene, and alkylene oxides.In some embodiments, one or more synthetic (co)polymers may comprise polyacrylic acid (PAA), polyacrylamide (PAN), tertiary butylsulfonic acid. acrylamide (ATBS) (or AMPS, 2-acrylamide-2-methylpropane sulfonic acid), N-vinylpyrrolidone (NVP), polyvinyl alcohol (PVA), or a mixture or copolymer of any of these polymers. Copolymers may be made from any of the above combinations, for example, a combination of NVP and ATBS. In certain examples, one or more synthetic (co)polymers may comprise acrylamide tert-butyl sulfonic acid (ATBS) (or AMPS, 2-acrylamide-2-methylpropane sulfonic acid) or a copolymer thereof. In some embodiments, one or more synthetic (co)polymers may comprise acrylamide (co)polymers. In some embodiments, one or more acrylamide (co)polymers comprise water-soluble acrylamide (co)polymers. In several embodiments, the acrylamide (co)polymers comprise at least 30% by weight, or at least 50% by weight, acrylamide units with respect to the total amount of all monomeric units in the (co)polymer. Optionally, acrylamide (co)polymers may comprise, in addition to acrylamide, at least one additional comonomer. In example embodiments, the acrylamide (co)polymer may comprise less than about 50%, or less than about 40%, or less than about 30%, or less than about 20% by weight of at least one comonomer. In some embodiments, the additional comonomer may be a water-soluble, ethylenically unsaturated comonomer, in particular monoethylenically unsaturated comonomer. Additional suitable water-soluble comonomers include comonomers that are miscible with water in any proportion, but it is sufficient that the monomers dissolve sufficiently in an aqueous phase to copolymerize with acrylamide. In some cases, the solubility of such additional monomers in water at room temperature may be at least 50 g / L (e.g., at least 150 g / L, or less than 250 g / L). Other suitable water-soluble comonomers may comprise one or more hydrophilic groups. Hydrophilic groups may be, for example, functional groups comprising one or more atoms selected from the group of atoms O, N, S, and P. Examples of such functional groups include carbonyl groups (C-O), ether groups (-O-), in particular polyethylene oxide groups (CH2-CH2-O-). n-, , where n is preferably a number from 1 to 200, hydroxy groups -OH, ester groups -C(O)O-, primary, secondary or tertiary amino groups, ammonium groups, amide groups -C(O)-NH- or acid groups such as carboxyl groups -COOH, sulfonic acid groups -SO3H, phosphonic acid groups -POsH2 or phosphoric acid groups -OP(OH)3- Examples of monoethylenically unsaturated comonomers comprising acid groups include monomers comprising -COOH groups, such as acrylic acid or methacrylic acid, crotonic acid, itaconic acid, maleic acid, or Fumaric acid, monomers comprising sulfonic acid groups, such as vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2-methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido-3-methylbutanesulfonic acid, or 2-acrylamido-2,4,4-trimethylpentanesulfonic acid, or monomers comprising phosphonic acid groups, such as vinylphosphonic acid, allylphosphonic acid, N-(meth)acrylamidoalkylphosphonic acids, or (meth)acryloyloxyalkylphosphonic acids. Of course, the monomers can be used as salts. The -COOH groups in polyacrylamide copolymers can be obtained not only by copolymerizing acrylic amide and monomers comprising -COOH groups, but also by hydrolyzing derivatives of -COOH groups after polymerization. For example, the -CO-NH2 amide groups of acrylamide can be hydrolyzed to yield -COOH groups. Also worth mentioning are acrylamide derivatives such as N-methyl(meth)acrylamide, N,N'-dimethyl(meth)acrylamide, and N-methylolacrilamide; N-vinyl derivatives such as N-vinylformamide, N-vinylacetamide, N-vinylpyrrolidone, and N-vinylcaprolactam; and vinyl esters such as vinyl formate and vinyl acetate. N-vinyl derivatives can be hydrolyzed after polymerization to vinylamine units, and vinyl esters to alcohol units. vinyl. Other illustrative comonomers include monomers comprising hydroxy and / or ether groups, such as for example hydroxyethyl(meth)acrylate, hydroxypropyl(meth)acrylate, allyl alcohol, hydroxyvinyl ethyl ether, hydroxyvinyl propyl ether, hydroxyvinyl butyl ether, or polyethylene oxide (meth)acrylates. Other illustrative comonomers are monomers that have ammonium groups, i.e., monomers that have cationic groups. Examples include salts of 3-trimethylammonium propylacrylamides or ethyl(meth)acrylates of 2-trimethylammonium, for example the corresponding chlorides, such as 3-trimethylammonium propylacrylamide chloride (DIMAPAQUAT) and 2-trimethylammonium ethyl methacrylate chloride (MADAME-QUAT). Other examples of monoethylenically unsaturated monomers include monomers that can cause hydrophobic association of (co)polymers. Such monomers comprise, in addition to the ethyl group and a hydrophilic part, a hydrophobic part as well. These monomers are described, for example, in WO 2012 / 069477, which is incorporated herein by reference in its entirety. Other examples of comonomers include N-alkylacrylamides and quaternary N-alkylacrylamides, in which the alkyl group comprises, for example, an alkyl group C2-C28. In certain embodiments, each of one or more acrylamide (co)polymers may optionally comprise crosslinking monomers, i.e., monomers comprising more than one polymerizable group. In certain embodiments, one or more acrylamide (co)polymers may optionally comprise crosslinking monomers in an amount of less than 0.5%, or 0.1%, by weight, based on the amount of all monomers. In one embodiment, each of one or more acrylamide (co)polymers comprises at least one monoethylenically unsaturated comonomer comprising acidic groups, for example, monomers comprising at least one group selected from -COOH, -SO3H, or -PO3H2. Examples of such monomers include, but are not limited to, acrylic acid, methacrylic acid, vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, most preferably acrylic acid and / or 2-acrylamido-2-methylpropanesulfonic acid, and more preferably acrylic acid or its salts. The amount of such comonomers comprising acidic groups may be from 0.1% to 70%, from 1% to 50%, or from 10% to 50% by weight based on the amount of all monomers. In one embodiment, each of one or more acrylamide (co)polymers comprises 50% to 90% by weight of acrylamide units and 10% to 50% by weight of acrylic acid units and / or their respective salts, based on the total weight of all monomers that make up the copolymer. In one embodiment, each One of one or more acrylamide (co)polymers comprises 60% to 80% by weight of acrylamide units and 20% to 40% by weight of acrylic acid units, based on the total weight of all monomers that make up the copolymer. In some embodiments, one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) are in particulate form, dispersed in the emulsion or LP. In some embodiments, the particles of one or more synthetic (co)polymers may have an average particle size of 0.4 pm to 5 pm, or 0.5 pm to 2 pm. The average particle size refers to the dso value of the particle size distribution (average number) as measured by laser diffraction analysis. In some embodiments, one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) may have a weight average molecular weight (M w ) from 5,000,000 g / mol to 30,000,000 g / mol; from 10,000,000 g / mol to 25,000,000 g / mol; or from 15,000,000 g / mol to 25,000,000 g / mol. In some embodiments, the LP composition may comprise one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) dispersed in one or more hydrophobic liquids. In these embodiments, the amount of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) in the LP composition may be at least 39% by weight, based on the total weight of the composition. In these modalities, the amount of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) in the LP composition can be 39% to 80% by weight, or 40% to 60% by weight, or 45% to 55% by weight, based on the total amount of all components of the composition (before dilution). In some embodiments, the amount of one or more synthetic (co)polymers (for example, one or more acrylamide (co)polymers) in the LP composition is 39%, 40%, 41%, 42%, 43%, 44%, 45%, 46%, 47%, 48%, 49%, 50%, 51%, 52%, 53%, 54%, 55%, 56%, 57%, 58%, 59%, 60%, or greater, by weight, based on the total amount of all components of the composition (before dilution). In some embodiments, the LP composition may comprise one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) emulsified in one or more hydrophobic liquids. In these embodiments, the amount of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) in the LP composition may be less than 38% by weight, or less than 35% by weight, or less than 30% by weight based on the total weight of the composition. In some of these forms, the amount of one or more synthetic (co)polymers (for example, one or more acrylamide (co)polymers) in the LP composition may be 10% to 35% by weight, 10% to 38% by weight, 15% to 30% by weight, 15% to 38% by weight, 20% to 38% by weight, or 20% to 30% by weight, based on the total amount of all components of the composition (before dilution). In some embodiments, the amount of one or more synthetic (co)polymers (for example, one or more acrylamide (co)polymers) in the LP composition is 38%, 37%, 36%, 35%, 34%, 33%, 32%, 31%, 30%, 29%, 28%, 27%, 26%, 25%, 24%, 23%, 22%, 21%, 20%, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or less, by weight, based on the total amount of all components of the composition (before dilution). Emulsifying surfactants In some embodiments, the LP composition may include one or more emulsifying surfactants. In some embodiments, one or more emulsifying surfactants are surfactants capable of stabilizing water-in-oil emulsions. Emulsifying surfactants, among other things, reduce the interfacial tension between water and the water-immiscible liquid in the emulsion to facilitate the formation of a water-in-oil polymer emulsion. It is known in the art to describe the ability of surfactants to stabilize water-in-oil or oil-in-water emulsions using the so-called "HLB value" (hydrophilic-lipophilic equilibrium). The HLB value is usually a number from 0 to 20. In surfactants with a low HLB value, the lipophilic parts of the molecule predominate, and therefore they are generally good water-in-oil emulsifiers. In surfactants with a high HLB value, the hydrophilic parts predominate. The hydrophilic parts of the molecule predominate, and therefore they are generally good oil-in-water emulsifiers. In surfactants with a high HLB value, the hydrophilic parts of the molecule predominate, and therefore they are generally good oil-in-water emulsifiers. In some embodiments, one or more emulsifying surfactants are surfactants with an HLB value of 2 to 10, or a mixture of surfactants with an HLB value of 2 to 10. Examples of suitable emulsifying surfactants include, but are not limited to, sorbitan esters, in particular sorbitan monoesters with C12-C18 groups such as sorbitan monolaurate (HLB approximately 8.5), sorbitan monopalmitate (HLB approximately 7.5), sorbitan monostearate (HLB approximately 4.5), sorbitan monooleate (HLB approximately 4); sorbitan esters with more than one ester group such as sorbitan tristearate (HLB approximately 2), sorbitan trioleate (HLB approximately 2); ethoxylated fatty alcohols with 1 to 4 ethylenexy groups, for example polyoxyethylene dodecyl ether (4) (HLB value approximately 9), polyoxyethylene hexadecyl ether (2) (HLB value approximately 5), and polyoxyethylene oleyl ether (2) (HLB value approximately 4). Exemplary surfactant emulsifiers include, but are not limited to, emulsifiers that have HLB values ​​of 2 to 10 (for example, less than 7). Such suitable emulsifiers include sorbitan esters, phthalic esters, fatty acid glycerides, glycerin esters, as well as ethoxylated versions of the above and any other well-known emulsifier with a relatively low HLB. Examples of such compounds include sorbitan monooleate, the reaction product of oleic acid with isopropanolamide, hexadecyl sodium phthalate, decyl sodium phthalate, sorbitan stearate, ricinoleic acid, hydrogenated ricinoleic acid, lauric acid glyceride monoester, stearic acid glyceride monoester, oleic acid glycerol diester, 12-hydroxystearic acid glycerol triester, ricinoleic acid glycerol triester, and ethoxylated versions thereof containing 1 to 10 moles of ethylene oxide per mole of the basic emulsifier.Thus, any emulsifier that allows the formation of the initial emulsion and stabilizes it during the polymerization reaction can be used. Examples of surfactant emulsifiers also include modified polyester surfactants, anhydride-substituted ethylene copolymers, N,N-dialkanol-substituted fatty amides, and tallow amine ethoxylates. In one embodiment, the inverse emulsion or LP composition comprises 0% to 5% by weight (e.g., 0.05% to 5%, 0.1% to 5%, or 0.5% to 3% by weight) of one or more emulsifying surfactants, based on the total weight of the composition. Emulsifying surfactants can be used alone or in mixtures. In some embodiments, the inverse emulsion or LP composition may comprise less than 5% by weight (for example, less than 4% by weight, or less than 3% by weight) of one or more emulsifying surfactants, based on the total weight of the composition. Process stabilizing agents In some embodiments, the LP composition may optionally include one or more process stabilizing agents. The process stabilizing agents are intended to stabilize the dispersion of the acrylamide poly(co)polymer particles in the organic and hydrophobic phase and optionally also to stabilize the aqueous monomeric phase droplets in the organic hydrophobic liquid before and during the polymerization or processing of the LP composition. The term "stabilizer" usually means that the agents prevent dispersion, flocculation, and aggregation. Process stabilizing agents can be any stabilizing agent, including surfactants, whose objective is such stabilization. In certain examples, process stabilizing agents can be oligomeric or polymeric surfactants. Due to the fact that oligomeric and polymeric surfactants can have many anchoring groups, they are very strongly adsorbed onto The surface of the particles, and the oligomers / polymers themselves, are capable of forming a dense spherical barrier on the particle surface that prevents aggregation. The average molecular weight (Mn) of such polymeric or oligomeric surfactants can range from 500 to 60,000 g / mol (e.g., 500 to 10,000 g / mol, or 1,000 to 5,000 g / mol). Oligomeric and / or polymeric surfactants suitable for stabilizing polymer dispersions are known to those skilled in the art. Examples of such stabilizing polymers include amphiphilic block copolymers comprising hydrophilic and hydrophobic blocks, amphiphilic copolymers comprising hydrophilic and hydrophobic monomers, and amphiphilic comb polymers comprising a hydrophobic main chain and hydrophilic side chains or alternatively a hydrophilic main chain and hydrophobic side chains. Examples of amphiphilic block copolymers include block copolymers comprising a hydrophobic block consisting of alkyl acrylates having longer alkyl chains, for example, C6 to C22 alkyl chains, such as hexyl(meth)acrylate, 2-ethylhexyl(meth)acrylate, octyl(meth)acrylate, dodecyl(meth)acrylate, hexadecyl(meth)acrylate, or octadecyl(meth)acrylate. The hydrophilic block may comprise hydrophilic monomers such as acrylic acid, acid methacrylic or vinylpyrrolidone. Investment surfactants In some embodiments, the LP composition may optionally include one or more inverting surfactants. In some embodiments, one or more emulsifying surfactants are surfactants that can be used to accelerate the formation of an inverted composition (for example, an inverted (co)polymer solution) after mixing the inverted emulsion or LP composition with an aqueous fluid. Suitable inversion surfactants are known in the art, and include, for example, nonionic surfactants comprising a hydrocarbon group and a sufficiently hydrophilic polyalkylenoxy group. In some cases, nonionic surfactants defined by the general formula R can be used. 1 —0— (CH (R 2 ) —CH2^O) n H (I), where R 1 is a C8-C22 hydrocarbon group, such as an aliphatic C10-C18 hydrocarbon group, n is a number of = 4, preferably = 6, and R 2 is H, methyl or ethyl, on the condition that at least 50% of the R groups 2 These are H. Examples of such surfactants include polyethoxylates based on Cio-Cis alcohols, such as Ci2 / i4z C14 / 18 or Ci6 / is fatty alcohols, C13 or C13 / 15 oxoalcohols. The HLB value can be adjusted by selecting the number of ethoxy groups. Specific examples include tridecyl alcohol ethoxylates comprising 4 to 14 ethyleneoxy groups (e.g., tridecyl alcohol-8 EO (HLB value approximately 13-14)) or C12 / 14 fatty alcohol ethoxylates (e.g., C12 / 14 • 8 EO HLB value of approximately 13)). Examples of surfactant emulsifiers also include modified polyester surfactants, anhydride-substituted ethylene copolymers, N,N-dialkanol-substituted fatty amides, and tallow amine ethoxylates. Other suitable inversion surfactants include anionic surfactants, such as, for example, surfactants comprising phosphate groups or phosphonic acid. In some embodiments, one or more inversion surfactants may comprise polyoxyethylene sorbitol tetraoleate, C12-14 branched ethoxylated alcohol, or polyethylene glycol monooleate. In certain embodiments, one or more inversion surfactants may comprise 1 to 20 mol% of polyoxyethylene sorbitol tetraoleate, 60 to 80 mol% of C12-14 branched ethoxylated alcohol, and approximately 15 to approximately 25 mol% of polyethylene glycol monooleate. In some forms, the amount of one or more inverting surfactants in the inverted emulsion or LP composition is 1% to 10% (e.g., 0% to 5%) by weight, based on the total amount of all components of the inverted emulsion or LP composition. In certain versions, one or more can be added surfactants for inverting the inverted emulsion or composition LP directly after the preparation of the composition comprising one or more (co)acrylamide polymers dispersed in one or more hydrophobic liquids, and optionally one or more emulsifying surfactants (i.e., the inverted emulsion or polymer composition in liquid dispersion that is transported from the place of manufacture to the place of use already comprises one or more inverting surfactants). In another embodiment, one or more inverting surfactants may be added to the inverted emulsion or LP composition at the place of use (e.g., at an offshore production site). Other components Other optional components can be added to the inverted emulsion or LP composition. Examples of such components include radical scavengers, oxygen scavengers, chelating agents, biocides, stabilizers, or sacrificial agents. Preparation of LP compositions LP compositions can be synthesized according to the following procedures. In a first step, an inverse emulsion (water-in-oil emulsion) of acrylamide (co)polymers can be synthesized using procedures known to those skilled in the art. Such inverse emulsions can be obtained by polymerizing an aqueous solution of acrylamide and other comonomers, such as ethylenically unsaturated comonomers. Water-soluble, emulsified in a hydrophobic oil phase. In a further step, the water within such inverse emulsions can be reduced to less than 10% by weight or less than 5% by weight. Suitable techniques are described, for example, in U.S. Patent No. 4,052,353, U.S. Patent No. 4,528,321, or DE 24 19 764 A1, each of which is incorporated herein by reference in its entirety. For polymerization, an aqueous monomer solution comprising acrylamide and optionally other comonomers can be prepared. Acrylamide is a solid at room temperature, and aqueous solutions comprising approximately 50% by weight of acrylamide are commercially available. If comonomers with acidic groups, such as acrylic acid, are used, the acidic groups can be neutralized by adding aqueous bases such as aqueous sodium hydroxide. The concentration of all monomers together in the aqueous solution should usually be 10% to 60% by weight based on the total of all components of the monomer solution, or 30% to 50%, or 35% to 45% by weight. The aqueous solution of acrylamide and comonomers can be emulsified in one or more hydrophobic liquids using one or more emulsifying surfactants. One or more emulsifying surfactants can be added to the mixture or to the monomer solution or hydrophobic liquid before mixing. Other surfactants can be used in addition to one or more emulsifying surfactants, such as a surfactant stabilizer. The emulsion can be made in the usual way, for example by shaking the mixture. After an emulsion has formed, polymerization can be initiated by adding oil- and / or water-soluble initiators for radical polymerization to the emulsion. The initiators can be dissolved in water or water-miscible organic solvents such as alcohols. They can also be added as an emulsion. Exemplary polymerization initiators include organic peroxides such as tert-butyl hydroperoxide, sodium sulfite, sodium disulfite, or organic sulfites, sodium ammonium peroxodisulfate, iron(II) salts, or azo groups comprising initiators such as AIBN. In certain formulations, one or more chain transfer agents may be added to the mixture during polymerization. Generally, chain transfer agents have at least one weak chemical bond, thus facilitating the chain transfer reaction. Any conventional chain transfer agent may be used, such as propylene glycol, isopropanol, 2-mercaptoethanol, sodium hypophosphite, dodecyl mercaptan, thioglycolic acid, other thiols, and halocarbons, such as carbon tetrachloride. The chain transfer agent is usually present in an amount of 0.001 percent to 10 percent by weight of the total emulsion, although higher concentrations may be used. use more. The polymerization temperature is typically 30°C to 100°C, 30°C to 70°C, or 35°C to 60°C. Heating can be achieved using external heat sources and / or heat can be generated, particularly at the start of polymerization, by the polymerization reaction itself. Polymerization times can range, for example, from approximately 0.5 hours to approximately 10 hours. The polymerization produces an inverse emulsion comprising an aqueous phase of one or more (co)acrylamide polymers dissolved or swollen in water wherein the aqueous phase is emulsified in an organic phase comprising one or more hydrophobic liquids. In order to convert the inverse emulsion obtained into LP compositions to be used in the methods described herein, after polymerization, part or all of the water is distilled from the emulsion, thus yielding particles of one or more acrylamide (co)polymers emulsified in one or more hydrophobic liquids. For liquid polymer compositions, water is removed to a level of less than 10%, or less than 7%, or less than 5%, or less than 3% by weight. In exemplary embodiments, water removal is carried out by any suitable means, for example, at reduced pressure, such as from 30 hPa to 500 hPa, preferably from 50 hPa to 250 hPa. The temperature during water removal can typically be from 70°C to 100°C, although techniques that remove water at higher temperatures can be used. In certain embodiments, one or more of the hydrophobic liquids used in the inverse emulsion can be a low-boiling liquid, which can be distilled together with the water as a mixture. After removing the desired amount of water, the other optional components can be added. In some forms, the manufacture of liquid polymer compositions is carried out in a chemical production plant. Inverted polymer solutions Also provided herein are inverted polymer solutions, as well as methods for preparing inverted polymer solutions from the LP compositions described herein and methods for using the inverted polymer solutions in oil and gas operations. The methods for preparing inverted polymer solutions from the LP compositions described herein may comprise inverting the LP composition in an aqueous fluid to provide an inverted polymer solution having a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) from 50 to 15,000 ppm. In some embodiments, the inverted polymer solution may have a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) of at least 50 ppm (e.g., at least 100 ppm, at least 250 ppm, at least 500 ppm, at least 750 ppm, at least 1,000 ppm, at least 1,500 ppm, at least 2,000 ppm, at least 2,500 ppm, at least 3,000 ppm, at least 3,500 ppm, at least 4,000 ppm, at least 4,500 ppm, at least 5,000 ppm, at least 5,500 ppm, at at least 6,000 ppm, at least 6,500 ppm, at least 7,000 ppm, at least 7,500 ppm, at least 8,000 ppm, at least 8,500 ppm, at least 9,000 ppm, at least 9,500 ppm, at least 10,000 ppm, at least 10,500 ppm, at least 11,000 ppm, at least 11,500 ppm, at least 12,000 ppm, at least 12,500 ppm, at least 13,000 ppm, at least 13,500 ppm, at least 14,000 ppm, or at least 14,500 ppm). In some embodiments, the inverted polymer solution may have a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) of 15,000 ppm or less (e.g., 14,500 ppm or less, 14,000 PPm or less, 13, 500 PPm or less, 13,000 PPm or less, 12,500 PPm or less, 12. 000 ppm or less, 11,500 ppm or less, 11,000 ppm or less, 10,500 ppm or less, 10,000 ppm or less, 9,500 ppm or less, 9,000 ppm or less, 8,500 ppm or less, 8,000 ppm or less, 7,500 ppm or less, 7,000 ppm or less, 6,500 ppm or less, 6,000 ppm or less, 5,500 ppm or less, 5,000 ppm or less, 4500 ppm or less; The inverted polymer solution may have a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) ranging from any of the minimum values ​​described above to any of the maximum values ​​described above. For example, in some embodiments, the inverted polymer solution may have a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) of 500 to 5000 ppm (e.g., 500 to 3000 ppm, or 500 to 1500 ppm). In some embodiments, the inverted polymer solution can be an unstable aqueous colloidal suspension. In other embodiments, the inverted polymer solution can be a stable aqueous suspension. In some forms, the inverted polymer solution may have a filtration rate of 1.5 or less (e.g., 1.4 or less, 1.4 or less, 1.35 or less, 1.3 or less, 1.25 or less, 1.2 or less, 1.15 or less, 1.1 or less, or less than 1.05) at 15 psi (1.05 kg / cm²). 2 ) using a 1.2yim filter. In some embodiments, the inverted polymer solution may have a filtration rate greater than 1 (e.g., at least 1.05, at least 1.1, at least 1.15, at least 1.2, at least 1.25, at least 1.3, at least 1.35, at least 1.4, or at least 1.45) at 15 psi (1.05 kg / cm 2 ) using a 1.2pm filter. The inverted polymer solution can have a filtration rate at 15 psi using a 1.2 pm filter that varies from any of the minimum values ​​described above to any of the maximum values ​​described above. For example, in some embodiments, the inverted polymer solution can have a filtration rate of 1 to 1.5 (e.g., 1.1 to 1.4, or 1.1 to 1.3) at 15 psi (1.05 kg / cm²). 2 ) using a 1.2pm filter. In certain formulations, the inverted polymer solution can have a viscosity based on the shear rate, temperature, salinity, polymer concentration, and polymer molecular weight. In some formulations, the inverted polymer solution can have a viscosity of 2 cP to 100 cP, where 2 cP to 100 cP is an output that uses the ranges in the following table: Polymer viscosity (cP) 2 ~ 100 Shear rate (1 / sec.) 0.1 ~ 1000 Temperature (°C) 1 ~ 120 Salinity (ppm) 0 ~ 250,000 Polymer concentration (ppm) 50 ~ 15,000 Polymer molecular weight (Dalton) 2M ~ 26M In some embodiments, the inverted polymer solution may have a viscosity of 25 cP to 35 cP at 30°C. In some embodiments, the inverted polymer solution may have a viscosity greater than 10 cP at 40°C. In certain embodiments, the inverted polymer solution may have a viscosity of 20 cP to 30 cP at 40°C. In some embodiments, when the LP composition is inverted in an aqueous fluid, providing an inverted polymer solution that has 50 to 15,000 ppm, 500 to 5,000 ppm, or 500 to 3,000 ppm of active polymer, the inverted polymer solution has a viscosity of at least 20 cP at 40°C, and a filtration rate (FR) (1.2 micron filter) of 1.5 or less. In certain embodiments, when the LP composition is inverted in an aqueous fluid, providing an inverted polymer solution that has 50 to 15,000 ppm, 500 to 5,000 ppm, or 500 to 3,000 ppm of active polymer, the inverted polymer solution has a viscosity of at least 20 cP at 30°C, and a filtration rate (FR) (1.2-micron filter) of 1.5 or less. As used herein, "inverted" refers to the point at which the viscosity of the inverted polymer solution has substantially reached a consistent viscosity.In practice, this can be determined, for example, by periodically measuring the viscosity of the inverted polymer solution over time, and when three consecutive measurements are within the error standard for the . measurement, then the composition is considered inverted. In some modalities, the inversion of the LP forms the inverted polymer solution in 30 minutes or less (e.g., 15 minutes or less, 10 minutes or less, 5 minutes or less, or less). As described above, methods for preparing an inverted polymer solution from the LP composition described herein may involve inverting the LP composition in an aqueous fluid to provide an inverted polymer solution having an acrylamide (co)polymer concentration of 50 to 15,000 ppm. The inversion of the LP composition may be carried out as a batch or continuous process. In certain embodiments, the inversion of the LP composition may be carried out as a continuous process. For example, the inversion of the LP composition may be carried out as a continuous process to produce a fluid stream for injection into a hydrocarbon-bearing formation. A continuous process is a process that can be carried out without the need for intermittent stopping or slowing.For example, continuous processes can satisfy one or more of the following criteria: (a) the materials to form the inverted polymer solution (e.g., LP composition and aqueous fluid) are fed into the system in which the inverted polymer solution is produced at the same rate as . (a) the inverted polymer solution is removed from the system; (b) the nature of the composition(s) introduced into the system in which the inverted polymer solution is produced is a function of the position of the composition(s) with the process as it flows from the point at which the composition(s) are introduced into the system to the point at which the inverted polymer solution is removed from the system; and / or (c) the amount of inverted polymer solution produced is a function of (i) the duration during which the process is operated and (ii) the process throughput rate. The inversion of the LP composition may comprise a single step or a plurality of steps (i.e., two or more steps). In some embodiments, the inversion of the LP composition may be carried out in a single step. In these embodiments, the LP composition (e.g., a composition having at least 39% (e.g., 39% or more) by weight of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) dispersed in a hydrophobic liquid, or a composition having up to 35% (e.g., less than 35%) by weight of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) emulsified in a hydrophobic liquid) may be inverted in an aqueous fluid to provide an inverted polymer solution having a concentration of one or more synthetic (co)polymers (e.g., one or more acrylamide (co)polymers) of 50 to 15,000 ppm. The simple inversion stage may involve diluting the LP composition in the aqueous fluid in an in-line mixer to provide the inverted polymer solution. For example, a polymer feed stream comprising the LP composition may be combined (e.g., in a fixed ratio) with an aqueous fluid stream upstream of an in-line mixer. The combined fluid stream may then pass through the in-line mixer, emerging as the inverted polymer solution. In some embodiments, the in-line mixer may have a mixer inlet and a mixer outlet, and the pressure differential between the mixer inlet and mixer outlet is from 15 psi to 400 psi (1.05 kg / cm²). 2 at 28.12 kg / cm 2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2 ), from 15 psi to 100 psi (1.05 kg / cm 2 at 7.03 kg / cm 2 ), or 15 psi to 75 psi) (1.05 kg / cm 2at 5.27 kg / cm 2 ) . An illustrative system for the inversion of LP compositions in a single stage is shown schematically in Figure 1. As shown in Figure 1, a pump 102 can be used to inject a stream of LP composition 104 into a line 106 carrying the aqueous fluid stream. The combined fluid stream can then pass through an in-line mixer 108 having an inlet from mixer 110 and an outlet from mixer 112, emerging as the inverted polymer solution. The pressure drop across the Inline mixer 108 (Ap) can be from 15 psi to 400 psi (1.05 kg / cm²) 2 at 28.12 kg / cm 2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2 ), from 15 psi to 100 psi (1.05 kg / cm 2 at 7.03 kg / cm 2 ), or 15 psi to 75 psi) (1.05 kg / cm 2 at 5.27 kg / cm 2 ). In other embodiments, the inversion of the LP composition can be carried out in two or more stages (for example, an inversion stage in which the LP composition is inverted in the aqueous fluid to form a concentrated polymer composition having a polymer concentration of up to 15,000 ppm; and one or more dilution stages in which the concentrated polymer composition is diluted in the aqueous fluid to provide the inverted polymer solution). For example, the inversion of the LP composition can be carried out in two, three, four, five, or more consecutive stages. In certain cases, the inversion of the LP composition can be carried out in two stages.In these embodiments, the LP inversion may comprise, as a first stage, inverting the LP composition in an aqueous fluid in a first in-line mixer having a first mixer inlet and a first mixer outlet to provide an inverted polymer solution with a concentration of synthetic (co)polymer (e.g., acrylamide (co)polymer) that is up to 15,000 ppm (e.g., from 5,000 to 15,000 ppm); and as a second stage, diluting the inverted polymer solution in the aqueous fluid in a second in-line mixer having a second inlet. from the mixer and a second mixer outlet to provide the inverted polymer solution. For example, a polymer feed stream comprising composition LP can be combined (e.g., in a fixed ratio) with an aqueous fluid stream upstream of a first in-line mixer. The combined fluid stream can then pass through the first in-line mixer, emerging as an inverted polymer solution with a concentration of synthetic (co)polymer (e.g., acrylamide (co)polymer) of up to 15,000 ppm (e.g., from 5,000 to 15,000 ppm). The fluid stream can then be combined (e.g., in a fixed ratio) with a second aqueous fluid stream upstream of a second in-line mixer. The combined fluid stream can then pass through the second in-line mixer, emerging as the inverted polymer solution.In some embodiments, the first in-line mixer may have a first mixer inlet and a first mixer outlet, and the pressure difference between the first mixer inlet and the first mixer outlet may be from 15 psi to 400 psi (1.05 kg / cm²). 2 at 28.12 kg / cm 2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2 ), from 15 psi to 100 psi (1.05 kg / cm 2 at 7.03 kg / cm 2 ), or 15 psi to 75 psi) (1.05 kg / cm 2 at 5.27 kg / cm 2 ) . In some models, the second online mixer It may have a second mixer inlet and a second mixer outlet, and the pressure difference between the second mixer inlet and the second mixer outlet may be from 15 psi to 400 psi (1.05 kg / cm²). 2 at 28.12 kg / cm 2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2), from 15 psi to 100 psi (1.05 kg / cm²) 2 at 7.03 kg / cm 2 ), from 15 psi to 75 psi) (1.05 kg / cm 2 at 5.27 kg / cm 2 ). An illustrative system for the inversion of LP compositions in two stages is shown schematically in Figure 2. As shown in Figure 2, a pump 102 can be used to inject a stream of LP composition 104 into the branch 101 mounted on the main line 103 carrying the aqueous fluid stream. A valve 105 positioned on the main line 103 downstream of the branch 101 can be used to direct the flow of aqueous fluid through the branch 101. The combined fluid stream can then pass through a first in-line mixer 108 having a first mixer inlet 110 and a first mixer outlet 112, emerging as the inverted polymer solution with a concentration of synthetic (co)polymer (e.g., acrylamide (co)polymer) up to 15,000 ppm (e.g., from 5,000 to 15,000 ppm).The pressure drop across the first in-line mixer 108 (Api) can be from 15 psi to 400 psi (1.05 kg / cm). 2 at 28.12 kg / cm 2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2 ), of 15 psi to 100 psi (1.05 kg / cm²) 2 at 7.03 kg / cm 2 ), or 15 psi to 75 psi) (1.05 kg / cm 2 at 5.27 kg / cm 2 The inverted polymer fluid stream 114 can then be combined (for example, in a fixed ratio) with the aqueous fluid stream in the main line 103 upstream of a second in-line mixer 116. The combined fluid stream can then pass through a second in-line mixer 116 having a second mixer inlet 118 and a second mixer outlet 120, emerging as the inverted polymer solution. The pressure drop across the second in-line mixer 116 (Ap2) can be from 15 psi to 400 psi (1.05 kg / cm²). 2 at 28.12 kg / cm2 ) (for example, from 15 psi to 150 psi (1.05 kg / cm²) 2 at 10.54 kg / cm 2 ), from 15 psi to 100 psi (1.05 kg / cm 2 at 7.03 kg / cm 2 ), or 15 psi to 75 psi) (1.05 kg / cm 2 at 5.27 kg / cm 2 ). The LP compositions described herein may also be reversed using procedures and inversion systems known in the art, and such as those described in U.S. Patent No. 8,383,560, which is hereby incorporated by reference in its entirety. Another illustrative system for reversing LP compositions is shown schematically in Figure 3. As shown in Figure 3A, a pump 102 can be used to direct a stream of LP composition 104 to the LP manifold 122. The LP manifold 122 can include a manifold inlet LP 124 through which composition LP enters collector LP 122, and a plurality of collector outlets LP 126 (in this example, three collector outlets) through which streams of composition LP exit collector LP 122. The system may also include a main line 103 carrying an aqueous fluid stream to aqueous fluid collector 128. Aqueous fluid collector 128 may include an aqueous fluid collector inlet 130 through which aqueous fluid enters aqueous fluid collector 128, and a plurality of aqueous fluid collector outlets 132 (in this example, three collector outlets) through which aqueous fluid streams exit aqueous fluid collector 128.Each LP composition stream exiting the LP manifold 122 can then be combined with an aqueous fluid stream exiting the aqueous fluid manifold 128 in a different in-line mixer configuration 134, thereby forming a plurality of parallel inverted polymer solution streams. The in-line mixer configuration 134 for LP composition inversion comprises parallel single stages, parallel multiple stages, or any combination thereof. Figure 3B shows an example of an in-line mixer configuration 134 comprising a combination of a single-stage and a two-stage parallel inversion process. Any of the suitable online mixer(s) They can be used in conjunction with the inversion methods described above. The in-line mixer can be either a dynamic or a static mixer. Suitable dynamic mixers, which involve mechanical agitation of one type or another, are known in the art and include impeller mixers, turbine mixers, rotor-stator mixers, colloid mills, pumps, and pressure homogenizers. In some embodiments, the in-line mixer(s) can comprise a dynamic mixer such as an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump. In some embodiments, the in-line mixer(s) can also comprise static mixers. Static mixers are mixers that mix fluids in flow without the use of moving parts.Static mixers are generally constructed from a series of stationary, rigid elements that form intersecting channels to divide, rearrange, and combine component streams, resulting in a homogeneous liquid flow. Static mixers provide simple and efficient solutions to mixing and contact problems. More affordable than dynamic agitator systems, static mixing units offer a long service life with minimal maintenance and low pressure drop. Static mixers can be manufactured from metals and / or plastics to fit existing piping and vessels. virtually any size and shape. In some cases, the static mixer may include a piping region, for example a coiled pipe region that facilitates mixing. The aqueous fluid used to invert the LP composition may comprise 0 to 250,000 ppm; 15,000 to 160,000 ppm; 15,000 to 100,000 ppm; 10,000 to 50,000 ppm; 15,000 to 50,000 ppm; 30,000 to 40,000 ppm; 10,000 to 25,000 ppm; 10,000 to 20,000 ppm; or 15,000 to 16,000 ppm of total dissolved solids (TDS). In one illustrative embodiment, the aqueous fluid may comprise a brine having approximately 15,000 ppm of TDS. In one embodiment, the brine may be a synthetic seawater brine as illustrated in Table 1. Table 1. Composition of an illustrative synthetic seawater brine. Ions (ppm) Synthetic seawater brine Na+ 10800 K+ 400 Ca+ 410 Mg++ 1280 Cl- 19400 TDS 32290 The aqueous fluid used to invert the compositions LP may comprise produced reservoir brine, reservoir brine, seawater, fresh water, produced water, water, saltwater (e.g., water containing one or more dissolved salts), brine, synthetic brine, synthetic seawater brine, or any combination thereof. In general, the aqueous fluid may comprise water from any readily available source, provided it does not contain an excess of compounds that could adversely affect other components in the inverted polymer solution or render the inverted polymer solution unsuitable for its intended use (e.g., unsuitable for use in an oil and gas operation such as an EOR operation). If desired, aqueous fluids obtained from natural sources may be treated prior to use.For example, aqueous fluids may be softened (e.g., to reduce the concentration of divalent and trivalent ions in the aqueous fluid) or otherwise treated to adjust their salinity. In certain embodiments, the aqueous fluid may comprise soft brine or hard brine. In certain embodiments, the aqueous fluid may comprise produced reservoir brine, reservoir brine, seawater, or a combination thereof. In one modality, seawater is used as the aqueous fluid, since offshore production facilities tend to have an abundance of seawater available. Limited storage space and transportation costs to an offshore site are typically high. If seawater is used as the aqueous fluid, it can be softened before the addition of the suspended polymer, thereby removing multivalent ions in the water (e.g., specifically Mg). 2+and Ca 2+ ) . In some models, the aqueous fluid can have a temperature of 1°C to 120°C. In other models, the aqueous fluid can have a temperature of 45°C to 95°C. The investment methods described herein can be specifically adapted for use in a particular oil and gas operation. For example, in some configurations, LP investment can be performed as a continuous process to produce a fluid stream for injection into a hydrocarbon-bearing formation. In some cases, the in-line mixer (or one or more in-line mixers in the case of multi-stage inversion procedures) may be located downstream of the surface pumping equipment (e.g., on land, on a ship, or on an offshore platform) that pumps the LP composition and aqueous fluid. In certain embodiments, the in-line mixer (or one or more in-line mixers in the case of multi-stage inversion procedures) may be positioned at or near the wellhead of a well. In certain embodiments, the in-line mixer may be located in the bottom of the well. In certain configurations, the in-line mixer (or one or more in-line mixers in the case of multi-stage inversion procedures) may be positioned on the underlying surface, below the sea surface, or at the bottom of the well. In certain configurations, the hydrocarbon-bearing formation may be a subsurface reservoir. In these configurations, the in-line mixer (or one or more in-line mixers in the case of multi-stage inversion procedures) may be located downstream of the pumping equipment at the surface (e.g., onshore, on a vessel, or on an offshore platform) that pumps the LP composition and / or aqueous fluid. In certain configurations, the in-line mixer (or one or more in-line mixers in the case of multi-stage inversion procedures) may be positioned below the sea surface. Thus, depending on the oil and gas operation, for example, an in-line mixer may be positioned at the surface, on the subsurface, below the sea surface, or at the bottom of the well. In some embodiments, the in-line mixer can be part of an in-line polymer flood injection system. Referring now to Figure 4, in certain illustrative embodiments, the in-line polymer flood injection system 200 can be used in a formation having a source reservoir layer 202, divider or impermeable layers 204, and a target reservoir layer 206. The divider or impermeable layers 204 may include shale, a combination of shale and smaller source reservoirs, gas reservoirs, or other oil reservoirs. In certain illustrative embodiments, an injection well 208 is drilled in an injection zone and completed with casing 210. The injection well 208 is further completed by installing the injection system 200 inside it. In certain illustrative embodiments, the injection system 200 includes a water injection line 212 through which the aqueous fluid may be supplied, a chemical injection line 214 through which the LP composition may be supplied, and a static mixer 228.In addition, in certain illustrative embodiments, the injection well 208 is separated into a water collection zone 222, a mixing zone 224, and an injection zone 226. In certain illustrative embodiments, the water collection zone 222 is substantially aligned with the source reservoir layer 202 of the formation, the injection zone 226 is substantially aligned with the target reservoir layer 206 of the formation, and the mixing zone 224 is disposed between the water collection zone 222 and the injection zone 226. In certain illustrative modalities, such as the modality As illustrated in Figure 4, the water collection zone 222 is isolated between a first packing 218 located at the top of the water collection zone 222 and a second packing 220 located between the water collection zone 222 and the mixing zone 224. In certain illustrative embodiments, the water injection pipe 212 extends from the surface, where it is connected to a pipe string, and into the mixing zone 224, passing through the first packing 218 and the second packing 220. Consequently, the pipe string is in fluid communication with the mixing zone 224. In certain illustrative embodiments, the first packing 218 and second packing 220 are sealed around the water injection pipe 212.In certain illustrative embodiments, the water injection pipe 212 and casing 210 of injection well 208 include a plurality of perforations 230, which place the water injection pipe 212 in fluid communication with the source reservoir layer 202. Water from the source reservoir layer 202 flows to the water collection zone through perforations 230 in casing 210 and then to the water injection pipe 212 through perforations 230 in the water injection pipe 212. The water is then supplied to the mixing zone 224 through the water injection pipe 212. In certain illustrative embodiments, the injection pipe... Water 212 is coupled to a pump 216, which facilitates the entrainment of water from the source reservoir layer 202 and the injection of water into the mixing zone 224. In certain illustrative embodiments, the pump 216 controls the flow rate of water to the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 214 extends from the surface and terminates in the mixing zone 224. The chemical injection tubing 214 is coupled to a tubing string through which the LP composition can be delivered downhole to the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 214 passes through the first packer 218 and the second packer 220 such that the first packer 218 and the second packer 220 form a seal around the chemical injection tubing 214. In certain illustrative embodiments, the chemical injection tubing 214 passes through the water collection zone 222, while the interior of the chemical injection tubing 214 is isolated from the water collection zone 222.In certain illustrative embodiments, during operation, an LP composition is pumped to the mixing zone 224 from the surface through the chemical injection pipe 214. In certain illustrative embodiments, the LP composition is pumped to the mixing zone. 224 at a controlled rate. In certain illustrative embodiments, the LP composition is pumped into the mixing zone 224 at a fixed ratio with respect to the water (i.e., the aqueous fluid) pumped into the mixing zone 224 through the water injection pipe 212, such that the LP composition is inverted in the mixing zone 224, thereby forming an inverted polymer solution. In certain illustrative embodiments, when water and LP composition are injected into the mixing zone 224, the water and LP composition are forced to move through the static mixer 228. In certain illustrative embodiments, the static mixer 228 provides a pathway that has a plurality of obstacles that force the fluid to move through it along a circuitous path. Thus, when the water and LP composition are forced through the static mixer 228 together, the water and LP composition mix and exit the static mixer 228 as an inverted polymer solution. In certain illustrative embodiments, the inverted polymer solution is then injected into the injection zone 226 and finally injected into the surrounding target reservoir 206 through perforations 230 in the casing 210. The injection fluid injected into the target reservoir 206 increases the pressure in the target reservoir 206. This mobilizes the hydrocarbons in the target reservoir and It pushes the hydrocarbons towards a neighboring production well, where the hydrocarbons can be recovered. Figure 5 illustrates a second illustrative embodiment of an in-line polymer flood injection system. Elements that are the same as or comparable to those illustrated in the example shown in Figure 4 are identified by the same reference number in Figures 4-9. Similar to the example illustrated in Figure 4, the injection system 300 is installed within a cased injection well 208 that has a source reservoir layer 202 and a target reservoir layer 206. In certain illustrative embodiments, the injection well 208 is divided into a water collection zone 222, a mixing zone 224, and an injection zone 226.In certain illustrative embodiments, the injection system 300 includes a water collection pipe 302, a water injection pipe 304, an electric submersible pump (ESP) 306, a chemical injection pipe 308, and a static mixer 328. In certain illustrative embodiments, the water collection zone 222 is isolated between a first gasket 218 disposed at the top of the water collection zone 222 and a second gasket 220 disposed between the water collection zone 222 and the mixing zone 224. In certain illustrative embodiments, the water collection pipe 302 is extended. From water collection zone 222 to ESP 306, which is located above water collection zone 222. Water injection tubing 304 is arranged within water collection tubing 302 and extends from ESP 306 to mixing zone 224, passing through the first packer 218 and the second packer 220. In certain illustrative embodiments, water flows to water collection zone 222 from source reservoir 202 through a plurality of perforations 230 formed in the casing 210 of injection well 208. The water is conveyed to ESP 306 through water collection tubing 302, and then injected into mixing zone 224 through water injection tubing 304. ESP 306 can be used to control the water (i.e., aqueous fluid) rate. injected into the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 308 extends from the surface to and terminates in the mixing zone 224. The chemical injection tubing 308 is coupled to a tubing string through which an LP composition can be delivered downhole to the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 308 passes through the first packer 218 and the second packer 220 such that the first packer 218 and the second packer 220 form a seal around the product injection pipe Chemicals 308. In certain illustrative embodiments, the chemical injection pipe 308 passes through the water collection zone 222, while the interior of the chemical injection pipe 308 is isolated from the water collection zone 222. In this way, the LP composition is isolated from the ESP 306. In certain illustrative embodiments, the LP composition is pumped into mixing zone 224 at a controlled rate. In certain illustrative embodiments, LP composition is pumped into mixing zone 224 at a fixed ratio to water (i.e., aqueous fluid) pumped into mixing zone 224 through water injection pipe 304 and ESP 306, such that LP composition is inverted in mixing zone 224, thereby forming an inverted polymer solution. In certain illustrative embodiments, when water and LP composition are injected into the mixing zone 224, the water and LP composition are forced to move through the static mixer 328. When the water and LP composition are forced through the static mixer 328 together, the water and LP composition mix, and exit the static mixer 228 as an inverted polymer solution. In certain illustrative embodiments, the inverted polymer solution is then injected into the injection zone 226 and finally injected into the surrounding target reservoir 206 through perforations 230 in casing 210. The injection fluid injected into target reservoir 206 increases the pressure in target reservoir 206. This mobilizes the hydrocarbons in the target reservoir and pushes the hydrocarbons toward a neighboring production well, where the hydrocarbons can be recovered. Figure 6 illustrates a third illustrative modality of an online polymer discharge flood injection system. In certain illustrative embodiments, the injection system 400 includes a progressive cavity pump (PCP) 402, a chemical injection line 404, and a static mixer 406. In certain illustrative embodiments, the water collection zone 222 is isolated between a first packer 218 disposed at the top of the water collection zone 222 and a second packer 220 disposed between the water collection zone 222 and the mixing zone 224. In certain illustrative embodiments, water flows to the water collection zone 222 from the source reservoir 202 through perforations 230 formed in the casing 210 of the injection well 208. The PCP 402 extends from the water collection zone 222 to the mixing zone 224, passing through the second packer 220.In certain illustrative configurations, the PCP 402 pumps water from the water collection zone 222 to the mixing zone 224. The water collection zone 222 and the mixing zone. The PCP 402 and PCP 402 are isolated from each other. In one embodiment, the PCP 402 may include a stator and a drive rod, as well as an inlet at the top of the PCP 402 and an outlet at the bottom of the PCP 402. Water from the water collection zone 222 enters the PCP 402 through the inlet of the PCP 402, and water exits through the outlet of the PCP 402. In this way, the PCP 402 can be used to control the rate of water (i.e., aqueous fluid) injected into the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 404 extends from the surface to and terminates in the mixing zone 224. The chemical injection tubing 404 is connected to a tubing string through which an LP composition is delivered downhole to the mixing zone 224. In certain illustrative embodiments, the chemical injection tubing 404 passes through the first packer 218 and the second packer 220 such that the first packer 218 and the second packer 220 form a seal around the chemical injection tubing 404. In certain illustrative embodiments, the chemical injection tubing 404 passes through the water collection zone 222, while the interior of the chemical injection tubing 404 is isolated from the water collection zone 222. In this way, the LP composition is isolated from the PCP 402. In certain illustrative embodiments, the LP composition is pumped to the mixing zone 224 at a controlled rate. In certain illustrative embodiments, the LP composition is pumped to the mixing zone 224 at a fixed ratio with respect to the water (i.e., aqueous fluid) pumped to the mixing zone 224 through the PCP 402, such that the LP composition is inverted in the mixing zone 224, thereby forming an inverted polymer solution. In certain illustrative embodiments, when water and LP composition are injected into mixing zone 224, the water and LP composition are forced to move through static mixer 406. When the water and LP composition are forced through static mixer 406 together, the water and LP composition mix together and exit static mixer 406 as an inverted polymer solution. In certain illustrative embodiments, the inverted polymer solution is then injected into the injection zone 226 and finally injected into the surrounding target reservoir 206 through perforations formed in the casing pipe 210. Figure 7 illustrates a fourth illustrative embodiment of an in-line polymer flood injection system. In certain illustrative embodiments, the injection system 500 is installed in an injection well 208 that is separated into a water collection zone 222 and a zone of Injection 226. In certain illustrative embodiments, the water collection zone 222 is isolated between a first packer 218 disposed at the top of the water collection zone 222 and a second packer 220 disposed between the water collection zone 222 and the injection zone 226. In certain illustrative embodiments, the injection system 500 includes a water collection pipe 504, a water injection pipe 506, an ESP 502, a chemical injection pipe 512, and a static mixer 510. In certain illustrative embodiments, the chemical injection pipe 512 extends from the surface to the ESP 502, and the chemical injection pipe 512 does not pass through the first packer 218. For example, the chemical injection pipe 512 is coupled to a tubing string through which an LP composition is delivered downhole to the ESP 502.In certain illustrative embodiments, water (i.e., aqueous fluid) flows to the water collection zone 222 from the source reservoir 202 through a plurality of perforations 230 formed in the casing 210 of the injection well 208. In certain illustrative embodiments, the water collection pipe 504 extends from the water collection zone 222 to the ESP 502, which is located above the water collection zone 222. The pipe of . Water injection 506 is partially disposed within water collection pipe 504 and extends from ESP 502 to injection zone 226, passing through the first gasket 218 and the second gasket 220. Water (i.e., aqueous fluid) is conveyed to ESP 502 through water collection pipe 504, and the LP composition is conveyed to ESP 502 through chemical injection pipe 512 and then injected into injection zone 226 through water injection pipe 506. In certain illustrative embodiments, a static mixer 510 is disposed within water injection pipe 506, such that the water (i.e., aqueous fluid) and the LP composition are mixed together as they move through water injection pipe 506 and into injection zone 226, where they exit as an inverted polymer solution.The ESP 502 can be used to control the rate of water and LP composition injected into injection zone 226. In certain illustrative embodiments, the water injection pipe 506 includes a flow meter 508 that monitors the flow rate. In certain illustrative embodiments, the inverted polymer solution is then injected into injection zone 226 and finally injected into the surrounding target reservoir 206 through perforations formed in casing 210. Figure 8 illustrates a fifth illustrative modality of A flood injection system with in-line polymer discharge. In certain illustrative embodiments, the injection system 600 is installed in an injection well 208 that is divided into a water collection zone 222 and an injection zone 226. In certain illustrative embodiments, the water collection zone 222 is isolated between a first packer 218 disposed at the top of the water collection zone 222 and a second packer 220 disposed between the water collection zone 222 and the injection zone 226. In certain illustrative embodiments, the injection system 600 includes a chemical injection pipe 602, a PCP 604, and a static mixer 606. The PCP 604 may include a stator and a drive rod, as well as an inlet to the top of the PCP 604 and an outlet to the bottom of the PCP 604.In certain illustrative embodiments, water (i.e., aqueous fluid) flows to the water collection zone 222 from the source reservoir 202 through perforations 230 formed in the casing 210 of the injection well 208. The chemical injection tubing 602 extends to the water collection zone 222 from the surface. The PCP 604 is connected to the chemical injection tubing 602. In certain illustrative embodiments, one-way valves 610 and 612 are arranged at the injection tubing crossing. Chemical injection line 602 and PCP 604, and check valves 610 and 612 allow water to enter PCP 604 from water collection zone 222. Check valves 610 and 612 are intended to allow water from water collection zone 222 to pass through check valves 610 and 612 (and into PCP 604), but LP composition does not pass through check valves 610 and 612 into water collection zone 222. The water that passes through check valves 610 and 612 and the LP composition from chemical injection line 602 are pumped down through PCP 604. For example, water from water collection zone 222 and LP composition from chemical injection line 602 enters PCP 604 through the inlet of PCP 604 and exits through the outlet of PCP 604 to the static mixer 606.The static mixer 606 is coupled to the PCP 604 opposite the chemical injection pipe 602. In this way, water (i.e., aqueous fluid) and the LP composition are driven into the static mixer 606 by the PCP 604, where they are mixed together, and exit the static mixer 606 as an inverted polymer solution. In certain illustrative embodiments, the inverted polymer solution is then injected into the injection zone 226 and finally injected into the target reservoir surrounding 206 through the perforations 230 formed in the casing pipe 210. Figure 9 illustrates a sixth illustrative embodiment of an in-line chemical flood injection system. In certain illustrative embodiments, the injection system 700 is installed in an injection well 208 that is divided into a water collection zone 222 and an injection zone 226. In certain illustrative embodiments, the water collection zone 222 is isolated between a first packer 218 disposed at the top of the water collection zone 222 and a second packer 220 disposed between the water collection zone 222 and the injection zone 226. In certain illustrative embodiments, the injection system 700 includes a chemical injection pipe 702 and a static mixer 706. In certain illustrative embodiments, the chemical injection pipe 702 also includes a flow meter for measuring the flow rate.The chemical injection tubing 702 extends from the surface to the injection zone 226. In certain illustrative embodiments, water flows to the water collection zone 222 from the source reservoir 202 through perforations 230 formed in the casing 210 of the injection well 208. The source reservoir 202 has a particular pressure, which is illustrated. As shown in certain illustrative embodiments, the chemical injection pipe 702 also includes a plurality of perforations 230 that allow water to flow into the chemical injection pipe 702. An LP composition with a particular pressure, illustrated as P2, is pumped into the chemical injection pipe 702 from the surface. The water (i.e., aqueous fluid) and the LP composition flow into the static mixer 706, where they are mixed together, and exit the static mixer 706 as an inverted polymer solution. The inverted polymer solution is then injected into the injection zone 226 and finally into the surrounding target reservoir 206 through the perforations 230 formed in the casing 210. The target reservoir 206 has a particular pressure, illustrated as P3.As explained later, the pressure differences between Pl, P2, and P3 drive the water, the composition LP, or both to their destinations. In Figure 9, the pressure differences between Pl, P2, and P3 drive the water, the LP composition, or both to their destinations. For example, in some cases, the pressure in source reservoir 202 is greater than the pressure of the LP composition, and the pressure of the composition is greater than the pressure in target reservoir 206 (i.e., Pl > P2 > P3). The higher pressure in source reservoir 202 causes water to flow from source reservoir 202 into a region From the lower pressure, i.e., the water collection zone 222, the chemical injection pipe 702, and through the static mixer 706 to the target reservoir 206 with the lowest pressure. Similarly, the pressure of the LP composition causes it to flow to a lower pressure region, i.e., through the static mixer 706 to the target reservoir 206 with the lowest pressure. Since the pressure of the source reservoir 202 is higher than the pressure of the LP composition, the LP composition will not flow into the source reservoir 202. As in Figure 9, pressure differentials can also propel water, LP composition, or both to their destinations in some of the other modes. Furthermore, a pump (e.g., pump 216, ESP 306, 502, and PCP 402, 604), a valve (e.g., check valves 610, 612), pressure differentials, or any combination thereof can be used to propel water, LP composition, or both to their destinations. For example, in Figure 7, (a) the higher pressure of source reservoir 202 causes water to flow from source reservoir 202 to a lower pressure region such as water collection zone 222, (b) the contents of water collection zone 222 are carried to ESP 502 by the operation of ESP 502, and (c) the contents in ESP 502 are moved through water injection pipe 506 injection zone 226 is already affected by the operation of ESP 502. As discussed previously, the inverted polymer solutions described herein can be used in oil and gas operations, such as EOR operations. For example, the inverted polymer solutions described above can be used in polymer injection operations. In some cases, the inverted polymer solution also includes one or more additional agents to facilitate hydrocarbon recovery. For example, the inverted polymer solution may also include a surfactant, an alkalinity agent, a co-solvent, a chelating agent, or any combination thereof. As such, the inverted polymer solution can be used in polymer (P), polymer-alkali (AP), surfactant-polymer (SP), and / or surfactant-polymer-alkali (ASP) EOR operations.When present, these additional components can be incorporated into the aqueous fluid used to invert the LP composition prior to LP composition inversion. Alternatively, these additional components can be incorporated into the inverted polymer solutions after LP composition inversion. For chemical enhanced oil recovery (CEOR) operations, the LP composition can be dispersed in a current aqueous in a sufficient quantity for a The injection stream contains a target concentration of hydrated polymer and particle size. The target concentration varies depending on the type of polymer used, as well as the reservoir characteristics, such as the petrophysical properties of the rock, the reservoir fluid properties, and reservoir conditions like temperature, permeability, water composition, mineralogy, and / or reservoir location. In some cases, the inverted polymer solutions described herein are suitable for use in reservoirs with permeability ranging from 10 millidarcy to 40,000 millidarcy. The hydrated polymer molecules in the inverted polymer solution can have a particle size (radius of gyration) ranging from 0.01 to 10 pm in one modality. A characteristic of the reservoir is the median pore throats, which correspond to the reservoir permeability. Depending on the deposit, the median pore throats in reservoirs can range from 0.01 pm to several hundred micrometers. Since the size of hydrated polymers in water varies from 0.01 micrometers to several micrometers depending on the species, molecules, and reservoir conditions, in one modality, appropriate polymers are selected for the LP composition for Provide an inverted polymer solution where the particle size of the hydrated polymers is <10% of the average pore throat parameters. This can allow the hydrated polymer particles to flow through a porous medium in an uninhibited manner. In another embodiment, the hydrated polymer particles have an average particle size ranging from 2 to 8% of the average pore throat size. Surfactants may be included to lower the interfacial tension between the oil and water phases to less than 10⁻² dynes / cm (for example), thereby recovering additional oil by mobilizing and solubilizing the oil trapped by capillary forces. Examples of surfactants that may be used include, but are not limited to, anionic surfactants, cationic surfactants, amphoteric surfactants, nonionic surfactants, or a combination thereof. Anionic surfactants may include sulfates, sulfonates, phosphates, or carboxylates. Such anionic surfactants are known and described in the art, for example, in U.S. Patent No. 7,770,641, incorporated herein by reference in its entirety. Examples of specific anionic surfactants include internal dentin sulfonates, isomerized olefin sulfonates, alkyl sulfonates, medium alcohol alkoxysulfates (CIO to C17), [alkoxy]carboxylates of ethers of Alcohols and [alkoxy]sulfates of alcohol ethers are examples of surfactants. Illustrative cationic surfactants include primary, secondary, or tertiary amines, or quaternary ammonium cations. Illustrative amphoteric surfactants include cationic surfactants attached to a sulfonate or carboxylate terminal group. Examples of nonionic surfactants include alcohol alkoxylates such as alkylalkoxy alcohols or alkylalkoxy alcohols. Other nonionic surfactants may include alkyl alkoxylated esters and alkyl polyglycosides. In some embodiments, multiple nonionic surfactants such as nonionic alcohols or nonionic esters are combined. As a person skilled in the art can appreciate, the selection of surfactant(s) may vary depending on factors such as salinity, temperature, and clay content in the reservoir. Suitable alkalinity agents include bases, ionic salts of alkali metals, or alkaline earth metals. These alkalinity agents may be able to react with an unrefined petroleum acid (e.g., the acid or its precursor in crude oil (reactive petroleum)) to form soap (a surfactant that is a fatty acid salt) in situ. These in situ-generated soaps can serve as a source of surfactants that reduce the interfacial tension of the oil-in-water emulsion. thus reducing the viscosity of the emulsion. Examples of alkali agents include alkali metal hydroxides, carbonates, or bicarbonates, including, but not limited to, sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate, sodium citrate, and sodium tetraborate. In some cases, the alkalinity agent may be present in the inverted polymer solution in an amount of 0.3 to 5.0 percent by weight of the solution, such as 0.5 to 3 percent by weight. The inverted polymer solution may optionally include a co-solvent. A "co-solvent" refers to a compound that has the ability to increase the solubility of a solute in the presence of an unrefined petroleum acid. In the embodiments provided herein, the co-solvents have a hydrophobic portion (alkyl or aryl chain), a hydrophilic portion (e.g., an alcohol), and optionally an alkoxy portion. The co-solvents, as provided herein, include alcohols (e.g., Ci-Cs alcohols, Ci-Cg diols), alkoxy alcohols (e.g., Ci-Cg alkoxy alcohols, Ci-Ce alkoxydiols, and phenyl alkoxy alcohols), glycol ether, glycol, and glycerol. The term "alcohol" is used in its ordinary meaning and refers to an organic compound containing -OH groups attached to a carbon atom. The term "diol" is used according to its ordinary meaning and refers to an organic compound containing two -OH groups bonded to two different carbon atoms. The term "alkoxy alcohol" is used according to its ordinary meaning and refers to an organic compound containing an alkoxy linker bonded to an -OH group. The inverted polymer solution may optionally include a chelating agent. Chelating agents can be used to complex with the alkali metal and soften brines. If desired, the salinity of the inverted polymer solution can be optimized for a particular underground reservoir by adjusting the number of chelating ligands in the chelating agent, such as alkoxylate groups if the chelating agent is EDTA (ethylenediaminetetraacetic acid). EDTA is just one example of a suitable chelating agent; another example is MGDA (methylglycineacetic acid). If desired, other additives can also be included in the inverted polymer solutions described herein, such as biocides, oxygen scavengers, and corrosion inhibitors. Methods for its use The inverted polymer solutions described herein can be used in a variety of oil and gas operations, including an operation EOR (for example, an enhanced oil recovery (IOR) operation, a polymer injection operation, an AP injection operation, a SP injection operation, an ASP injection operation, a compliance control operation, or any combination thereof). Furthermore, the inverted polymer solutions described herein can be used in a variety of oil and gas operations, including hydraulic fracturing, as a friction reducer that reduces friction during fluid transport in a pipeline, or any combination thereof. Fluid transport in a pipeline can refer to any movement of a fluid through a conduit or tube.As such, the transport of a fluid in a pipeline includes, for example, the pipeline transport of fluids as well as the passage of fluids through tubes such as wells during the course of an oil recovery operation. = Inverted polymer solutions can still be used in water treatment operations associated with oil and gas operations. In one embodiment, the inverted polymer solution can be used as an injection fluid. In another embodiment, the inverted polymer solution can be included in an injection fluid. In yet another embodiment, the inverted polymer solution can be used as a fluid for Hydraulic fracturing. In another embodiment, the inverted polymer solution can be included in a hydraulic fracturing fluid. In another embodiment, the inverted polymer solution can be used as a friction reducer that reduces friction during fluid transport in a pipeline. In another embodiment, the inverted polymer solution can be included in a friction reducer that reduces friction during fluid transport in a pipeline. In summary, in certain embodiments, the inverted polymer solutions described herein can be used in hydrocarbon recovery. Methods for hydrocarbon recovery may include providing an underlying surface reservoir containing hydrocarbons; providing a well in fluid communication with the underlying surface reservoir; preparing an inverted polymer solution using the methods described above; and injecting the inverted polymer solution through the well into the underlying surface reservoir. For example, the underlying surface reservoir may be a subsurface reservoir and / or the underlying surface reservoir may have a permeability of 10 millidarcy to 40,000 millidarcy. The well in the second stage can be a borehole of an injection well associated with an injection well, and the method may further comprise providing a production well separated from the injection well by a predetermined distance and with a production well perforated in fluid communication with the underlying surface reservoir. In these embodiments, the injection of the inverted polymer solution can increase the flow of hydrocarbons to the production well. In some embodiments, hydrocarbon recovery methods may also include a recycling stage. For example, in some embodiments, hydrocarbon recovery methods may further comprise producing production fluid from the production well, where the production fluid includes at least a portion of the injected inverted polymer solution; and using the production fluid to invert the additional LP composition, for example, to form a second inverted polymer solution. The second inverted polymer solution may be injected into at least one well perforation (for example, an injection well, the same well discussed in the second stage, or a different well, etc.). Thus, in some embodiments, the inverted polymer solution is included in an injection fluid. The well in the second stage can be a hydraulic fracturing well that is in fluid communication with the underlying surface reservoir. Thus, in one embodiment, the inverted polymer solution injected in the fourth stage acts as a friction reducer, lowering friction during injection in the fourth stage. By doing this, the inverted polymer solution is used as a friction reducer, lowering friction during the transport of a fluid (e.g., hydraulic fracturing fluid) in a pipeline (e.g., the well or its components). In another embodiment, the inverted polymer solution is incorporated into a hydraulic fracturing fluid. By way of non-limiting example, the following are examples of certain modalities of the present description. EXAMPLES Methods and materials A synthetic brine was used as the brine base. The synthetic brine included the following: Na + , Ca 2+ , Mg 2+, Cl' , and a TDS of approximately 15,000 ppm. Since the pure liquid polymer (LP) was provided as a continuous oil polymer dispersion with 50% activity, the LP polymer was inverted and diluted to a target concentration of 2000 ppm in the synthetic brine by mixing at 500 rpm, using an overload mixer. In the laboratory, the 0.50% pure liquid polymer was inverted to a 1% LP solution in the synthetic brine, Using the overload mixer at 500 rpm for 2 hours. Then, the 1% inverted LP solution was diluted to the target 0.2% LP solution in the synthetic brine, using the overload mixer at 500 rpm for 2 to 24 hours. The 50% pure liquid polymer was also directly inverted to the target 0.2% LP polymer concentration in the synthetic brine, using the overload mixer for 3 to 24 hours. Since the pure liquid polymer (LP) was provided as a continuous polymer dispersion in oil with 50% activity, the LP polymer was inverted and diluted to a target concentration of 2000 ppm in synthetic brine by mixing at 500 rpm using an overload mixer. In the laboratory, the 50% pure liquid polymer was inverted to a 1% LP solution in synthetic brine using the overload mixer at 500 rpm for 2 hours. The inverted 1% LP solution was then diluted to the target 0.2% LP solution in synthetic brine using the overload mixer at 500 rpm for 2 to 24 hours. The 50% pure liquid polymer was also directly inverted to the target 0.2% LP polymer concentration in synthetic brine using the overload mixer for 3 to 24 hours. hours. The filtration rate (FR) of the inverted polymer solutions was determined using the standard procedure described, for example, in Koh, H. Experimental Investigation of the Effect of Polymers on Residual Oil Saturation. Ph.D. Dissertation, University of Texas at Austin, 2015; Levitt, D. The Optimal Use of Enhanced Oil Recovery Polymers Under Hostile Conditions. Ph.D. Dissertation, University of Texas at Austin, 2009; and Magbagbeola, OA Quantification of the Viscoelastic Behavior of High Molecular Weight Polymers used for Chemical Enhanced Oil Recovery. MS Thesis, University of Texas at Austin, 2008, each of which is incorporated herein by reference in full. Briefly, 300 ml of 2000 ppm inverted LP solution in synthetic brine was filtered through a 5.0 jam, 1.2 µm ISOPORE™ polycarbonate filter with a 47 mm diameter at a pressure of 15 psi (1.05 kg / cm³). 2) (plus or minus 10% of 15 psi) pressure and ambient temperature (25°C). As expressed in the following formula, the FR was calculated as the ratio of the time for 180 to 200 ml of the polymer solution to be filtered divided by the time for 60 to 80 ml of the polymer solution to be filtered. f 200 mi - 480 mi FR= —----- ? ---- c 80 ml - t 60 ml For the composition to qualify for the tests Additionally, the composition was required to exhibit an FR less than or equal to 1.2 through both filters. Since FR 1.2 was a strict laboratory requirement for polymer qualification, clean, laboratory-quality filtered water was used when necessary. Steady-state shear viscosities were measured in the range of 0.1 s-1 to 1000 s-1 at 25°C and 31°C using the double-wall cover geometry with a TA Instruments ARES-G2 rheometer. Polymer injectivity tests were performed separately using 2000 ppm LP in a 2000 mD Bentheimer sandstone at 31°C. The flow rate was set at 0.5 ml / min, corresponding to ~6 ft / day (1.82 m / day). The pressure difference between the inlet and outlet was measured using Rosemount differential pressure transducers. Oil recovery experiments were conducted using 2000 ppm LP in an unconsolidated sand pack of approximately 5000 mD at 31°C. The flow rate was set at 0.5 ml / min, corresponding to approximately 4 ft³ / day (1.21 ft³ / day). The pressure difference between the inlet and outlet was measured using Rosemount differential transducers. A viscous crude oil (80 cP at 31°C) was selected for this experiment. Results and discussion FR Test: Figure 11 shows a graph of the FR test performed for an inverted polymer solution using a 1.2 micron filter with a diameter of 47 mm at a pressure of 15 psi (1.05 kg / cm²) 2and a temperature of 25°C. As shown in Figure 11 and Table 2, the inverted LP solution (2000 ppm polymer) passes through the 1.2-micron filter with an FR less than or equal to 1.5. More specifically, Figure 11 illustrates an FR of 1.13. This result indicates the improved filterability of the inverted polymer solution. Viscosity Measurement: Figure 12 shows a viscosity representation for a wide range of shear rates for an inverted polymer solution (2000 ppm polymer in synthetic brine, measured at 31°C). The viscosity of the inverted polymer solution illustrates typical shear behavior over the wide shear rate range. The viscosity is measured as 24 cP at 10 s⁻¹ and 31°C. Injectivity Test: The inverted polymer solution was injected into Bentheimer outcrop sandstones. The purpose of the polymer injection was to evaluate the injectivity of the inverted polymer solution in the porous medium. Approximately 30 PV of 2000 ppm LP polymer in synthetic brine was injected into Bentheimer sandstone at a flow rate of 0.5 mL / min, corresponding to 6 ft / day. (1.82 m / day) at a temperature of 31°C. As shown in the Figure 10 shows that the pressure drop for the inverted polymer solution reaches steady state after 2 pore volumes (PV), indicating no plugging. The corresponding relative permeability background is also represented in Figure 10. The relative permeability of the inverted polymer solution after 28 PV was ~1, confirming core plugging. Oil Recovery Experiment: The ability of the inverted polymer solution to displace oil and enhance recovery was tested in Bentheimer Sandstone in the presence of crude oil. A viscous crude oil (80 cP at 31°C) was selected for the test. The inverted polymer solution was injected at the end of the water injection in separate core flooding experiments. Oil recovery and pressure drop are graphically represented in Figure 14. As can be seen in the figures, oil recovery improves as the inverted LP solution is injected, while the pressure drop for LP injection shows a steady-state and low value at the end of the experiment. The low steady-state pressure drop for the LP solution at the end of the experiment indicates improved performance, as the LP solution does not clog the core during oil recovery. Table 2. Summary of LP composition properties inverted. Polymer Polymer Concentration (ppm) 5 Pa Filter (15 psi, 25°C) 1.2 ppm Filter (15 psi, 25 Viscosity (cP) ® 31°C FR Time to 200 g (min) FR Time to 200 g (min) 10 s- 1 LP 2000 1.00 5.0 1.13 27 22 2000 1.01 4.4 1.19 25 21 2000 1.04 5.7 1.18 24 25 Validation of viscosity measurements and filtration tests using pilot-scale LP samples. Additional viscosity measurements and filtration tests were performed using full-scale produced samples. These included pilot-scale and commercial-scale samples, along with previously manufactured laboratory-scale samples. The results of the viscosity measurements and filtration ratio are summarized in Table 3. The viscosity performance as a function of polymer concentration was measured at 31°C. Figure 15 shows the viscosity performance curve as a function of concentration. A 10,000 ppm stock solution was prepared from 52% pure active polymer. From this stock solution, appropriate dilutions were made, and viscosities were measured between 0.1 s and 1 µl. _1 and 1000 -1 The viscosity values ​​in Figure 15 correspond to the shear rate of 10s -1 For a concentration of 2000 ppm of inverted polymer solution, the viscosity is around 23 cP and the yield The viscosity of the inverted polymer solution at 10,000 ppm is approximately 900 cP. Figure 16 shows the viscosity of the polymer as a function of the shear rate. As shown in Figure 16, the shear refinement behavior of the polymer solutions was observed. As the polymer concentrations increased, the shear refinement behavior changed from lower to higher shear refinement. Table 3. Summary of viscosity and filtration using pilot-scale samples. Viscosity Sample (< cP) @ 10 s-1 Challenge test, filtration at 15 ps! >2SC Pure Activity |8C) 2kppm(31C} FR(5um> time to2DQg(m) FJL(L2um) Time >200g(m) $•1 S2.4K 179 25 1.04 5.7 118 24 22 1 5 113 27 21 1.01 4.4 119 25 Ml 52.1% 152 26 1.05 62 132 28.4 1.03 60 122 25.2 143 BOiO M-2 south 128 25 1.04 61 144 30.8 M-3 50M 104 24 l.« 63 124 29.4 131 27.4 16 134 13.2 20 150 210 M-5 S0JX 101 21 1.04 5.0 124 24.0 139 262 19 122 14.4 19 130 165 M-6 51JX 107 21 < 4 131 260 137 27.8 18 121 160 PUS 50 JX 241 22 113 160 H* S(UX 252 20 127 160 TIC 5OJBÍ 599 24 124 205 Average 207 21 1.04 151 128 211 Std. Dev. 148 3 0.02 066 oio 53 The 2000 ppm inverted polymer solutions were prepared using different pilot-scale batches of the LP solutions (M1 to M5), and filtration tests were conducted as previously described. Figures 17A and 17B show the filtration ratio test results for different pilot-scale batches of the LP solutions using a 5-micrometer filter (Figure 17A) and a 1.2-micrometer filter (Figure 17B) at 15 psi. As shown in Figures 17A and 17B, the LP solutions produced a filtration ratio (FR) of 1.04 ± 0.02 for a 5-micrometer filter and 1.28 ± 0.1 for a 1.2-micrometer filter. Figure 18 shows a long-term injection test of a single-phase inverted polymer solution into a core. The core included a pressure tap two inches from the face, providing a pressure differential along the core's injection face. As shown in Figure 18, the constant pressure drop did not show a significant signal consistent with plugging of the sandstone core. Analysis of the pressure drop during subsequent water immersion also showed no plugging. To verify the long-term performance of inverted LP solutions, the relative permeability of the single-phase polymer immersion was normalized using methods known in the art (See SPE 179657, SPE IOR Symposium in Tulsa 2016, which is incorporated herein by reference in full.) Figure 19A shows the relative plugging when the results are normalized for each section to the total injected pore volumes for a conventional emulsifying polymer. These results indicate that the plugging rate is faster near the injection front compared to the back sections of the core. Conversely, as shown in Figure 19B, the inverted LP solutions show no significant plugging. Figure 20 shows the Permeability Reduction Factor (Rk) and the Normalized Damage Factor, s / ln(r s / r w) as a function of the filtration ratio to 1.2 (FR 1.2). As shown in Figure 20, Rk and the damage factor increase when Fr is greater than 1.5. These results suggest that injecting a polymer solution with an FR greater than 1.5 plugs the core, while an FR of 1.5 or less does not cause plugging in the core. Polymer cycle field tests: After validating the performance and blending of the polymers under laboratory conditions, the next stage was to evaluate the The mixing efficiency of the pure brine solution at a final polymer concentration was tested in large-scale field trials. The objective of the field trials was to demonstrate that the viscosity performance and filtration ratio could be achieved by using mixers with a single-stage configuration and mixers with a multi-stage configuration (with and without dynamic mixers) as described in Figures 1 and 2. The experimental results using a single-stage mixer are summarized in Table 3, and the experimental results using a multi-stage mixer are summarized in Table 4. Each experiment was conducted using static mixing elements and different configurations, including dynamic mixers, varying flow rates, and different ratios of pure polymer to brine. After each run, samples were collected, and filtration tests and viscosity measurements were performed to verify the hydration of the polymer, including inversion and dilution through the designed mixing system. Table 4. Summary of field tests of polymer cycles - single-stage mixing example. n«-Exec. Mixing scheme Mixer vaioc. flow Speed ​​Mixing dynamics Viscosity ícP. 31 Cj Filtration Stage 1 Stage 2 (inversion, (Dilution, gpm (m / sj X3S-1 lfls-1 0 TRll (WMU Sl CMpUMÍQL. l'©: 15 elements 3C 3.7 Y 21.7 153 1 120 izo S-2 !*•; ISeiaMMitDa 30 3.7 21.2 195 1.14 S3 125 >3 «tlfHIMM» 2*©: 15 elements 55 3 Y .26.7 233 1 120 120 5-4 stage 2*©: 15 elements 55-IDO 3.1 N 25.7 23.5 1.07 10C 1S0 Table 5. Summary of field tests of cycles polymers - example of multi-stage mixing. Exec. n.- Mixing scheme Mixer veMcoe VekKHfoc MOM twaae (d»,31C) Filtration tn'eekor » Stage 1 (inversion) Stage 2 (dilution) H»™ (m / s) 7.JS-1 ios-i Rt (URn) Ml two stages l - * 15 elements 2* <t>15 elements 12 5-130 3^ / 3.9 i-.: — 1.3 55 140 M-2 dos stages i**: 15 elements elements 125 34 / 5.S ¥ 23 201 1.13 140 M-3 dos stages element 2 - ©: 15 elements 100 23 / 3.1 ¥ 23 20 .1.2 35 100 As shown in Figure 21, viscosity yields were measured at approximately 20 cP in both the multi-stage (two) and single-stage mixing configurations, with and without the dynamic mixer. This demonstrates that the LP is adequately hydrated through the static mixers in both single-stage and multi-stage configurations. Figures 22A and 22B show the viscosity yield as a function of pressure drop across the static mixers (Figure 22A) and the filtration ratio as a function of pressure drop across the static mixers (Figure 22B). To hydrate the LP and provide adequate viscosity yield and filtration capacity, a filtration ratio (FR) of 1.5 or less than 1.2 micrometers should be used. In general, field tests of polymer cycles demonstrate that successful viscosity yields can be achieved with a suitable filtration ratio by using a single-stage mixing process or multiple stages. In addition, injection experiments through a rock substitute did not show appreciable plugging behavior. The compositions and methods for the appended claims are not limited in scope by the specific compositions and procedures described herein, which are intended as illustrations of some aspects of the claims. It is intended that all compositions and procedures that are functionally equivalent fall within the scope of the claims. It is also intended that various modifications of the compositions and procedures, in addition to those described herein, fall within the scope of the appended claims. Furthermore, although certain representative compositions and method steps are specifically described herein, it is also intended that other combinations of the compositions and method steps fall within the scope of the appended claims, even if not specifically indicated.Therefore, a combination of stages, elements, components, or constituents may be explicitly mentioned here or less; however, other combinations of stages, elements, components, and constituents are included, even if they are not explicitly stated. The term "comprising" and its variations as used herein are used synonymously with The term "including" and its variations are open, non-limiting terms. Although the terms "comprising" and "including" have been used here to describe various embodiments, the terms "consisting essentially of" and "consisting of" may be used instead of "comprising" and "including" to provide more specific embodiments of the invention and are also described. Apart from where indicated, all numbers expressing geometries, dimensions, and so forth used in the claims and specification are to be understood, at a minimum, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, to be interpreted in light of the number of significant digits and ordinary rounding approximations. It is understood that when combinations, subsets, groups, etc., of elements are described (for example, combinations of components in a composition, or combinations of steps in a method), while specific reference to each of the various individual and collective combinations and permutations of these elements cannot be explicitly disclosed, each is specifically considered and described herein. By way of example, if a composition is described herein as including a component of type A, a component of type B, a component of type C, or any By combining these components, it is understood that this phrase describes all the various individual and collective combinations and permutations of these components. For example, in some modalities, the composition described by this phrase might include only a component of type A. In some modalities, the composition described by this phrase might include only a component of type B. In some modalities, the composition described by this phrase might include only a component of type C. In some modalities, the composition described by this phrase might include a component of type A and a component of type B. In some modalities, the composition described by this phrase might include a component of type A and a component of type C. In some modalities, the composition described by this phrase might include a component of type B and a component of type C.In some forms, the composition described by this phrase could include one component of type A, one component of type B, and one component of type C. In some forms, the composition described by this phrase could include two or more components of type A (e.g., A1 and A2). In some forms, the composition described by this phrase could include two or more components of type B (e.g., B1 and B2). In some forms, the composition described by this phrase could include two or more components of type C (e.g., C1 and C2). In some forms, the composition... The composition described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some modalities, the composition described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some modalities, the composition described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C)., two or more type C components (Cl and C2)), optionally one or more of a second component (for example, optionally one or more type A components), and optionally one or more of a third component (for example, optionally one or more type B components). This application relates to the subject matter of U.S. Provisional Application No. 62 / 264,772, filed on December 8, 2015; U.S. Provisional Application No. 62 / 264,700, filed on December 8, 2015; U.S. Provisional Application No. 62 / 264,701, filed on December 8, 2015; and the US provisional application no. 62 / 264,703, filed on December 8, 2015, each of which is incorporated herein in its entirety by reference. Unless otherwise defined, all technical and scientific terms used herein have the same meanings as commonly understood by a person skilled in the art to which the described invention pertains. Publications cited herein and the materials from which they are cited are specifically incorporated by reference. It is hereby stated that, as of this date, the best method known to the applicant for putting the aforementioned invention into practice is that which is clear from the present description of the invention.< / t>

Claims

CLAIMS Having described the invention as above, the following claims are claimed as property:

1. A method for preparing an inverted polymer solution characterized in that it comprises provide a liquid polymer composition (LP) comprising: one or more hydrophobic liquids that have a boiling point of at least 100°C; at least 39% by weight of one or more synthetic (co)polymers; one or more emulsifying surfactants; and one or more investment surfactants; invert the LP composition in an aqueous fluid to provide an inverted polymer solution having a synthetic (co)polymer concentration of 50 to 15,000 ppm; where the inverted polymer solution has a filtration rate of 1.5 or less at 15 psi using a 1.2 l / min filter; and where the inverted polymer solution is used in an enhanced oil recovery (EOR) operation.

2. The method according to claim 1, characterized in that the inverted polymer solution is an unstable aqueous colloidal suspension.

3. The method according to claim 1 characterized in that the inverted polymer solution is a stable aqueous suspension.

4. The method according to any of claims 1-3, characterized in that the inverted polymer solution has a filtration rate of 1.1 to 1.3 at 15 psi using the 1.2pm filter.

5. The method according to any of claims 1-4, characterized in that the inversion of the LP composition forms the inverted polymer solution in 30 minutes or less.

6. The method according to any of claims 1-5, characterized in that the inversion of the LP composition forms the inverted polymer solution in 5 minutes or less.

7. The method according to any of claims 1-6, characterized in that the reversal of the LP composition comprises a continuous process.

8. The method according to any of claims 1-7, characterized in that the reversal of the LP composition comprises a single step.

9. The method according to claim 8, characterized in that the single step comprises diluting the LP composition in the aqueous fluid in an in-line mixer having a mixer inlet and a mixer outlet to provide the inverted polymer solution.

10. The method according to claim 9, characterized in that the pressure difference between the mixer inlet and the mixer outlet is from 15 psi to 400 psi.

11. The method in accordance with claim 9 or 10, characterized in that the in-line mixer comprises a static mixer.

12. The method according to claim 9 or 10, characterized in that the in-line mixer comprises a dynamic mixer.

13. The method according to claim 12, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

14. The method according to any of claims 9-13, characterized in that the in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

15. The method according to any of claims 1-7, characterized in that the reversal of the LP composition comprises multiple steps.

16. The method according to claim 15, characterized in that the reversal of the LP composition comprises as a first step, reverse the LP composition in the aqueous fluid in a first in-line mixer having a first mixer inlet and a first mixer outlet to provide a concentrated polymer composition having a synthetic (co)polymer concentration of up to 15,000 ppm; and As a second stage, dilute the concentrated polymer composition in the aqueous fluid in a second in-line mixer that has a second mixer inlet and a second mixer outlet to provide the inverted polymer solution.

17. The method according to claim 16, characterized in that the pressure difference between the first mixer inlet and the first mixer outlet is from 15 psi to 400 psi.

18. The method in accordance with claim 16 or 17, characterized in that the first in-line mixer comprises a static mixer.

19. The method according to claim 16 or 17, characterized in that the in-line mixer comprises a dynamic mixer.

20. The method according to claim 19, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

21. The method according to any of claims 16-20, characterized in that the first The in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

22. The method according to any of claims 16-21, characterized in that the pressure difference between the second mixer inlet and the second mixer outlet is from 15 psi to 400 psi.

23. The method according to any of claims 16-22, characterized in that the second in-line mixer comprises a static mixer.

24. The method according to any of claims 16-22, characterized in that the in-line mixer comprises a dynamic mixer.

25. The method according to claim 24, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

26. The method according to any of claims 16-25, characterized in that the second in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

27. The method according to any of claims 1-26, characterized in that the aqueous fluid comprises soft brine or hard brine.

28. The method according to any of claims 1-27, characterized in that the aqueous fluid comprises produced reservoir brine, reservoir brine, seawater, fresh water, produced water, water, salt water, brine, synthetic brine, synthetic seawater brine, or any combination thereof.

29. The method according to any of claims 1-28, characterized in that the aqueous fluid further comprises a surfactant, an alkalinity agent, a co-solvent, a chelating agent, or any combination thereof.

30. The method according to any of claims 1-7, characterized in that the reversal of the LP composition comprises parallel single steps, parallel multiple steps, or any combination thereof.

31. The method according to claim 30, characterized in that the parallel single stages, parallel multiple stages, or any combination thereof include using at least one in-line mixer to dilute the LP composition in the aqueous fluid, wherein the in-line mixer has a mixer inlet and a mixer outlet to provide the inverted polymer solution.

32. The method according to claim 31, characterized in that the pressure difference between the mixer inlet and the mixer outlet is from 15 psi to 400 psi (1.05 kg / cm 2 at 28.12 kg / cm 2 ).

33. The method according to claim 31 or 32, characterized in that the in-line mixer comprises a static mixer.

34. The method according to claim 31 or 32, characterized in that the in-line mixer comprises a dynamic mixer.

35. The method according to claim 34, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

36. The method according to any of claims 31-35, characterized in that the in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

37. The method according to any of claims 1-36, characterized in that one or more synthetic (co)polymers comprise one or more acrylamide (co)polymers.

38. A method for preparing an inverted polymer solution characterized in that it comprises providing a liquid polymer composition (LP) in the form of an inverse emulsion comprising: one or more hydrophobic liquids that have a boiling point of at least 100°C; up to 38% by weight of one or more synthetic (co)polymers; one or more emulsifying surfactants; and one or more investment surfactants; invert the LP composition in an aqueous fluid to provide an inverted polymer solution having a synthetic (co)polymer concentration of 50 to 15,000 ppm; wherein the inverted polymer solution has a filtration rate of 1.5 or less at 15 psi using a 1.2pm filter; and where the inverted polymer solution is used in an enhanced oil recovery (EOR) operation.

39. The method according to claim 38, characterized in that the inverted polymer solution is an unstable aqueous colloidal suspension.

40. The method according to claim 38, characterized in that the inverted polymer solution is a stable aqueous suspension.

41. The method according to any of claims 38-40, characterized in that the inverted polymer solution has a filtration rate of 1.1 to 1.3 at 15 psi using the 1.2pm filter.

42. The method according to any of claims 38-41, characterized in that the inversion of the LP composition forms the polymer solution inverted in 30 minutes or less.

43. The method according to any of claims 38-42, characterized in that the inversion of the LP composition forms the inverted polymer solution in 5 minutes or less.

44. The method according to any of claims 38-43, characterized in that the reversal of the LP composition comprises a continuous process.

45. The method according to any of claims 38-44, characterized in that the reversal of the LP composition comprises a single step.

46. ​​The method according to claim 45, characterized in that the single step comprises diluting the LP composition in the aqueous fluid in an in-line mixer having a mixer inlet and a mixer outlet to provide the inverted polymer solution.

47. The method according to claim 46, characterized in that the pressure difference between the mixer inlet and the mixer outlet is from 15 psi to 400 psi.

48. The method according to claim 46 or 47, characterized in that the in-line mixer comprises a static mixer.

49. The method according to claim 46 or 47, characterized in that the in-line mixer comprises a dynamic mixer.

50. The method according to claim 49, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump or a progressive cavity pump.

51. The method according to any of claims 46-50, characterized in that the in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

52. The method according to any of claims 38-44, characterized in that the reversal of the LP composition comprises multiple steps.

53. The method according to claim 52, characterized in that the reversal of the LP composition comprises as a first step, inverting the LP composition in the aqueous fluid in a first in-line mixer having a first mixer inlet and a first mixer outlet to provide a concentrated polymer composition having a synthetic (co)polymer concentration of up to 15,000 ppm; and As a second stage, dilute the concentrated polymer composition in the aqueous fluid in a second in-line mixer that has a second mixer inlet and a second mixer outlet to provide the inverted polymer solution.

54. The method according to claim 53, characterized in that the pressure difference between the first mixer inlet and first mixer outlet is 15 psi to 400 psi (1.05 kg / cm²) 2 at 28.12 kg / cm 2 ) .

55. The method according to claim 53 or 54, characterized in that the first in-line mixer comprises a static mixer.

56. The method according to claim 53 or 54, characterized in that the in-line mixer comprises a dynamic mixer.

57. The method according to claim 56, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

58. The method according to any of claims 53-57, characterized in that the first in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

59. The method according to any of claims 53-58, characterized in that the pressure difference between the second mixer inlet and the second mixer outlet is from 15 psi to 400 psi (1.05 kg / cm²). 2 at 28.12 kg / cm 2 ) .

60. The method according to any of claims 53-59, characterized in that the second in-line mixer comprises a static mixer.

61. The method in accordance with any of claims 53-59, characterized in that the in-line mixer comprises a dynamic mixer.

62. The method according to claim 61, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

63. The method according to any of claims 53-62, characterized in that the second in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

64. The method according to any of claims 38-63, characterized in that the aqueous fluid comprises soft brine or hard brine.

65. The method according to any of claims 38-64, characterized in that the aqueous fluid comprises produced reservoir brine, reservoir brine, seawater, fresh water, produced water, water, salt water, brine, synthetic brine, synthetic seawater brine, or any combination thereof.

66. The method according to any of claims 38-65, characterized in that the aqueous fluid further comprises a surfactant, an alkalinity agent, a co-solvent, a chelating agent, or any combination of the same.

67. The method according to any of claims 38-44, characterized in that the reversal of the LP composition comprises parallel single steps, parallel multiple steps, or any combination thereof.

68. The method according to claim 67, characterized in that the parallel single stages, parallel multiple stages, or any combination thereof include using at least one in-line mixer to dilute the LP composition in the aqueous fluid, the in-line mixer having a mixer inlet and a mixer outlet to provide the inverted polymer solution.

69. The method according to claim 68, characterized in that the pressure difference between the mixer inlet and the mixer outlet is from 15 psi to 400 psi.

70. The method according to claim 68 or 69, characterized in that the in-line mixer comprises a static mixer.

71. The method according to claim 68 or 69, characterized in that the in-line mixer comprises a dynamic mixer.

72. The method according to claim 71, characterized in that the dynamic mixer comprises an electric submersible pump, a hydraulic submersible pump, or a progressive cavity pump.

73. The method according to any of claims 68-72, characterized in that the in-line mixer is positioned on the surface, underlying surface, below the sea surface, or at the bottom of the well.

74. The method according to any of claims 38-73, characterized in that one or more synthetic (co)polymers comprise one or more acrylamide (co)polymers.

75. The method according to any of claims 1-74, characterized in that the inverted polymer solution is used as an injection fluid.

76. The method according to any of claims 1-74, characterized in that the inverted polymer solution is included in an injection fluid.

77. The method in conformity with any of claims 1-76, characterized in that the EOR operation includes a polymer operation, an AP flooding operation, an SP flooding operation, an ASP flooding operation, a conformity control operation, or any combination thereof.

78. A method for the recovery of hydrocarbons, characterized in that it comprises: (a) provide an underlying surface reservoir containing hydrocarbons therein; (b) provide a well in fluid communication with the underlying surface reservoir; (c) prepare an inverted polymer solution according to the method in accordance with any of claims 1-74; and (d) inject the inverted polymer solution through the well into the underlying surface reservoir.

79. The method according to claim 78, characterized in that the well in step (b) is an injection well hole associated with an injection well, and the method further comprises provide a production well well separated from the injection well at a predetermined distance and have a production wellbore in fluid communication with the subsurface reservoir, where the injection of the inverted polymer solution in stage (d) increases the flow of hydrocarbons to the production well orifice.

80. The method according to claim 79, characterized in that it further comprises producing production fluid from the production well, the production fluid including at least a portion of the injected inverted polymer; and using the production fluid to invert the additional LP composition to form a second inverted polymer solution.

81. The method according to claim 81, characterized in that it further comprises injecting the second inverted polymer solution into at least one injection well.

82. The method according to any of claims 78-81, characterized in that the underlying surface reservoir is a submarine reservoir.

83. The method according to any of claims 78-82, characterized in that the underlying surface reservoir has a permeability from 10 millidarcy to 40,000 millidarcy.

84. The method according to any of claims 78-83, characterized in that the inverted polymer solution is used as an injection fluid.

85. The method according to any of claims 78-83, characterized in that the inverted polymer solution is included in an injection fluid.

86. The method according to any of claims 78-85, characterized in that for hydrocarbon recovery it comprises a method for carrying out an enhanced oil recovery (EOR) operation.

87. Method according to claim 86, characterized in that the EOR operation includes a polymer flooding operation, an AP flooding operation, an SP flooding operation, an ASP flooding operation, a conformity control operation, or any combination thereof.