WATER-SOLUBLE POLYMER DISPERSION FOR HYDRAULIC FRACTURING

Abstract

This application relates to an injection fluid F for hydraulic fracturing comprising at least one synthetic water-soluble polymer P with a weight-average molecular weight greater than or equal to 1 million daltons, and said fluid is prepared according to a process comprising the following successive steps: a) An inverse emulsion E is prepared by radical polymerization comprising between 15% and 40% by weight of polymer P, between 20% and 60% by weight of water and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of emulsion E, b) The inverse emulsion E is distilled to obtain a dispersion D comprising between 40% and 60% by weight of polymer P particles, less than 10% by weight of water and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of dispersion D,c) Dispersion D is diluted with 1% to 15% by weight of an aqueous solution S comprising between 20 and 60% by weight of salts, and the percentages are expressed by weight with respect to the weight of dispersion D.

Description

The invention relates to an injection fluid for hydraulic fracturing comprising at least one synthetic water-soluble polymer, and said fluid is a dispersion prepared by dilution with a brine of an inverse emulsion of said polymer, previously distilled. The invention also relates to a hydraulic fracturing procedure for underground unconventional oil and gas tanks using said injection fluid. The production of oil (oil, hydrocarbons) and gas contained in unconventional underground tanks has been developing for several years, and requires opening fractures in the reservoir for an economical production of oil and gas. Continuing the description of the prior art and the invention, the term "unconventional underground reservoirs" refers to deposits that require specific extraction technologies because they do not exist as an accumulation in porous and permeable rock (see: Les hydrocarbures de roche-mére en France Rapport provisoire CGIET n° 2011-04-G - Ministère de l'écologie, du développonent durable, des transports et du logement - Avríl 2011). (Boundary rock hydrocarbons in France Provisional Report - CGIET N° 2011-04-G - Ministry of Ecology, 1954082 of 41 Sustainable Development, Transport and Housing - April 2011). For unconventional gas, one can cite shale gas, coal bed methane, or tight reservoir oils. For unconventional gas, one can cite shale gas, coal bed methane, or tight reservoir oils. The reserves contained in unconventional reservoirs are enormous and extremely widespread in previously unexploitable areas, such as shale rock hydrocarbons, tight reservoir gas, and coal gas. In the United States, shale gas is widely exploited and currently accounts for 46% of total U.S. natural gas production, compared to only 28% in 1998. Extensive basins are known as the Barnett Shale, Villefayette Shale, Mowry Shale, Marcellus Shale, and Utica Shale. The exploitation of tight reservoirs has been made possible by advancements in drilling techniques. Indeed, production techniques have evolved from vertical wells to horizontal wells, reducing the number of production wells required and their 1954082 of 41 footprint on the ground and allows for better coverage of the reservoir volume to maximize gas or oil recovery. However, permeabilities are insufficient for the hydrocarbon to migrate easily from the source rock to the well, thus preventing economical and high-volume production of gas or oil. Therefore, it is necessary to increase permeability and production areas through stimulation operations, and in particular, through hydraulic fracturing of the rock in contact with the wells. Hydraulic fracturing Hydraulic fracturing aims to create additional permeability and generate larger gas or oil production areas. Indeed, low permeability, natural barriers from tight rock layers, and impermeability caused by drilling operations severely limit production. The gas or oil contained in the unconventional reservoir cannot easily migrate from the rock to the well without stimulation. These hydraulic fracturing operations in horizontal wells began in 1960 in the Appalachians, and currently, several tens of thousands of operations have taken place in the United States. 1954082 of 41 The technologies for studying, modeling the reservoir, drilling, foundation work, and stimulation have become increasingly sophisticated and use equipment that allows these operations to be carried out in increasingly shorter times with a precise analysis of the results. Reservoir stimulation by hydraulic fracturing These operations involve injecting water at high pressure and a very high flow rate to create fractures distributed perpendicularly in the production wells. This is generally done in several stages to create fractures along the entire length of the horizontal well, thus maximizing the volume of the reservoir. In order to keep these fractures open, a support agent (for example, sand, plastic materials or calibrated ceramics) is added to prevent the closure of these fractures, and to maintain the capillary action created once the injection has stopped. Water alone is insufficient for effective proppant placement due to its low viscosity. This limits its ability to hold the proppant in place within fractures. To address this issue, fracturing fluids containing viscosifying compounds have been developed. 1954082 of 41 By definition, a compound is said to be viscosifying when it increases the viscosity of the solutions in which it is dissolved. In addition to having viscosifying properties, the compound must have a specific rheological profile. Specifically, the compound must be able to generate low viscosity to avoid damaging the transport or pumping of the proppant-containing fluid during the high shear stresses experienced during fracturing fluid injection. Once injected, this same compound must be able to generate sufficient viscosity when the shear stress decreases to support the proppant and retain it in the fractures. Fracturing fluids generally comprise a polymer that must therefore provide the solution with re-fluidizing properties in order to have a relatively low viscosity during injection (high shear), and a high viscosity in order to keep the proppant in suspension at the fracture level when the shear decreases. The viscoelastic properties of the polymers in solution must also be taken into consideration. This viscoelasticity, and its importance in the application, is described in SPE document 147206 (Fracturing Fluid Compressed of Components Sourced Solely from the Food 1954082 of 41 Industry Provides Superior Proppant Transport David Loveless, Jeremy Holtsclaw, Rajesh Saini, Phil Harris, and Jeff Fleming, SPE, Halliburton) through visual observations in static or dynamic experiments, or also through rheological measurements, such as the measurement of viscous and elastic moduli (G' and G''), or the measurement of viscosity as a function of shear on a rheometer. In this way, the elastic properties will be advantageous to ensure the transport and suspension of the fracture support agent. Therefore, the choice of polymer is difficult and requires a thorough rheological study in order to obtain satisfactory results. Among the viscosifying compounds for aqueous solutions that are part of the prior art are natural substances such as guar gum and its derivatives, such as hydroxypropyl guar (HPG) or carboxymethylhydroxypropyl guar (CMHPG); and cellulosic derivatives such as carboxymethyl cellulose or hydroxyethyl cellulose. These compounds are described, in particular, in US patents 4033415, 3888312, and 4801389. In document SPE 152596 (Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and 1954082 of 41 Improving Frac Performance in Unconventional Gas and Oil Wells - George E. King, Apache Corporation), details the latest advances concerning the performance of fracturing fluids. However, these natural substances, and guar derivatives in particular, are also useful for other applications such as the food and textile industries, and the growth in the exploitation of unconventional oil and gas resources competes with these other applications. This puts pressure on the availability of these products and generates pricing problems. Other compounds resulting from petrochemicals can have viscosifying properties. Synthetic polymers are an example. Poly(meth)acrylamides, sometimes partially hydrolyzed, and poly(meth)acrylates and their copolymers are particularly well-known. These polymers develop viscosity due to their molar mass and interchain ionic repulsions. These polymers are described in patents GB 951147, US 3727689, US 3841402, and US 3938594. The mechanism governing viscosity is related to an increase in hydrodynamic volume due to interchain repulsions, interchain entanglement, and other factors. 1954082 of 41 However, in the presence of high salinity or at high operating temperatures, these polymers do not develop strong entanglement and repulsion, resulting in a significant decrease in their viscosity-increasing power, especially after being subjected to the shear stress of the pumping stage. Furthermore, these polymers generally do not possess sufficient viscoelastic properties to support the proppant in the fracture. It is necessary to increase the dosage of these polymers to excessively high levels to achieve the required proppant suspension properties. However, the necessary dosage levels are not economically viable. Advantageously, the polymers used to have viscosifying properties can also be friction reducers that allow reducing the pressure loss in turbulent medium, and greatly increasing the flow rate with the same power and pipe diameter. Synthetic polymers based on 2-acrylamido-2-methylpropane sulfonic acid and / or its salts exhibit interesting friction-reducing properties in aqueous solution. These polymers are also known for their shear strength and resistance to thermal degradation, especially in saline solutions. However, obtaining very high molecular weight polymers based on The use of 2-acrylamido-2-methylpropane sulfonic acid (1954082) is difficult, especially since these polymers exhibit solubility problems as their weight increases. Thus, to achieve optimal friction reduction and strong viscosity generation, it is essential that the polymer be rapidly soluble, particularly in saline solution, and have a very high molecular weight. For logistical, transportation, and supply reasons related to synthetic water-soluble polymers used in hydraulic fracturing, the preferred physical form of these polymers is powder, as it allows for a high percentage by weight of active material. The powder form of these polymers can be obtained by drying, heat drying, spray drying, and drum drying. However, when it is reconstituted, it requires specialized equipment, such as a wet powder slicing unit like a Polymer Slicing Unit (PSU). Polymer invert emulsions are also interesting, but they require rigorous optimization of their formulation, so that their inversion in aqueous medium is among the fastest, and that their stability (during storage and transport) is guaranteed (especially during freeze / thaw cycles). 1954082 of 41 PRESENTATION OF THE INVENTION The Applicant has discovered and perfected an injection fluid for hydraulic fracturing that provides significant friction reduction and viscosity-enhancing effects. This injection fluid is in the form of a water-soluble polymer dispersion and is prepared by diluting a previously distilled polymer inverse emulsion with brine. Surprisingly, the prior dilution of the distilled polymer emulsion (polymer dispersion) by a brine significantly increases its capacity to be inverted later in the injection salt waters (during injection into the underground formation), which implies an effective (rapid and almost total) dissolution of the polymer to maximize its application effect. The carbon footprint of this fluid is reduced because its concentrated polymer form implies lower transport costs, not to mention the absence of specific dissolution equipment for its use. Therefore, a first aspect of the invention relates to an injection fluid F for hydraulic fracturing comprising at least a synthetic water-soluble polymer P of weight average molecular weight greater than or 1954082 of 41 equal to 1 million daltons, and said fluid is prepared according to a procedure comprising the following successive steps: a) An inverse emulsion E is prepared by radical polymerization comprising between 15% and 40% by weight of polymer P, between 20% and 60% by weight of water and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of emulsion E, b) The inverse emulsion E is distilled to obtain a dispersion D comprising between 40 and 60% by weight of polymer particles P, less than 10% by weight of water and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of the dispersion D, c) Dispersion D is diluted with 1% to 15% by weight of an aqueous solution S comprising between 20% and 60% by weight of salts, and the percentages are expressed by weight with respect to the weight of dispersion D. A second aspect of the invention relates to a hydraulic fracturing procedure of an underground reservoir of unconventional oil or gas using the injection fluid F according to the invention. A third aspect of the invention relates to a friction reduction procedure that uses an injection fluid F in a hydraulic fracturing operation of an underground oil or gas reservoir. 1954082 of 41 conventional using injection fluid F according to the invention. As used herein, the expression "water-soluble polymer" designates a polymer that gives an aqueous solution without insoluble particles when dissolved under stirring for 4 hours at 25 °C and with a concentration of 20g.L-1 in water. According to the present invention, the "weight average molecular weight" of the synthetic water-soluble polymer P is determined by measuring its intrinsic viscosity. Intrinsic viscosity can be measured by methods known to the trade and can be calculated, primarily, from reduced viscosity values ​​for different concentrations using a graphical method. This method involves plotting reduced viscosity values ​​(on the y-axis) as a function of concentrations (on the x-axis) and extrapolating the curve to zero concentration. The intrinsic viscosity value is read on the y-axis or obtained using the least squares method. The weight average molecular weight can then be determined using the well-known Mark-Houwink equation: [η] = KM“ [η] represents the intrinsic viscosity of the polymer 1954082 of 41 determined by the solution viscosity measurement method, K represents an empirical constant, M represents the molecular weight of the polymer, a represents the Mark-Houwink coefficient, and a and K depend on the particular polymer-solvent system. Tables known to the trade give the values ​​of a and K according to the polymer-solvent system. The synthetic water-soluble polymer P of the invention has an average molecular weight advantageously greater than or equal to 1 million daltons, even more advantageously greater than or equal to 1.5 million daltons, and even more advantageously greater than or equal to 2 million daltons. Advantageously, it is less than or equal to 20 million daltons. Preferably, the synthetic water-soluble polymer P of the invention has an average molecular weight advantageously between 1 million daltons and 20 million daltons, even more advantageously between 1.5 million daltons and 20 million daltons, and even more advantageously between 2 million daltons and 20 million daltons. The inverse emulsion E comprising the synthetic water-soluble polymer P obtained by radical polymerization during step a) of the process of obtaining fluid F contains: 1954082 of 41 a hydrophilic phase comprising at least one water-soluble structured polymer; a lipophilic phase; at least one emulsifying agent; The lipophilic phase can be a mineral oil, a vegetable oil, a synthetic oil, or a mixture of several of these oils. Examples of mineral oils include mineral oils containing saturated hydrocarbons of the aliphatic, naphthenic, paraffinic, isoparaffinic, cycloparaffinic, or naphthyl type. Examples of synthetic oils include hydrogenated polydecene or hydrogenated polyisobutene, esters such as octyl stearate, or butyl oleate. Exxon's Exxsol® product range is perfectly suitable. Typically, the weight ratio of the hydrophilic phase to the lipophilic phase in the invert emulsion is preferably 50 / 50 to 90 / 10. In the present invention, the term "emulsifying agent" designates an agent capable of emulsifying water in oil, and a "reversing agent" is an agent capable of emulsifying oil in water. Generally, a reversing agent is considered to be a surfactant having an HLB greater than or equal to 10, and an emulsifying agent is a surfactant having an HLB strictly less than 10. 1954082 of 41 The hydrophilic-lipophilic (HLB) balance of a chemical compound is a measurement of its degree of hydrophilicity or lipophilicity, determined by calculating the values ​​of different regions of the molecule, as described by Griffin in 1949 (Griffin WC, Classification of Surface-Active Agents by HLB, Journal of the Society of Cosmetic Chemists, 1949, 1, pages 311-326). In the present invention, we have adopted Griffin's procedure based on calculating a value based on the chemical groups of the molecule. Griffin has assigned a dimensionless number between 0 and 20 to provide information about solubility in water and oil. Substances with an HLB value of 10 partition between the two phases, such that the hydrophilic group (molecular mass Mh) projects completely into the water, while the hydrophobic hydrocarbon group (molecular mass Mp) is adsorbed onto the non-aqueous phase. The HLB value of a substance of total molecular mass M whose hydrophilic part has a molecular mass Mh, is: HLB = 20 (Mh / M) The inverse emulsion E according to the invention is prepared by radical polymerization. An aqueous solution comprising the monomer(s) that allow obtaining the polymer P is emulsified in an oil phase comprising the emulsifying agent(s). Then, the polymerization is 1954082 of 41 is carried out by adding a free radical initiator. Redox pairs can be referred to as initiators, with eumene hydroperoxide, tertiary butylhydroperoxide, or persulfates among the oxidizing agents, and sodium sulfite, sodium metabisulfite, and Mohr's salt among the reducing agents. Azo compounds such as 2,2'-azobis(isobutyronitrile) hydrochloride or 2,2'-azobis(2-amidinopropane) hydrochloride can also be used. Classically, polymerization is generally carried out isothermally, adiabatically, or at a controlled temperature. This means that the temperature is kept constant, usually between 10 and 60 °C (isothermal), or the temperature is allowed to increase naturally (adiabatic). In the latter case, the reaction generally starts at a temperature below 10 °C, and the final temperature is generally above 50 °C. Finally, the temperature increase is controlled to obtain a temperature curve between the isothermal and adiabatic curves (controlled temperature). Polymerization can be carried out under pressure lower than atmospheric pressure, optionally, under conditions that allow some of the water and hydrocarbon solvent to evaporate from the reaction medium and pre-concentrate the emulsion. 1954082 of 41 The synthetic water-soluble polymer P preferably results from the polymerization of monounsaturated ethylene monomers that may be non-ionic, anionic, cationic, and / or zwitterionic. Preferably, these monomers are the following: - the non-ionic monomers selected from the group comprising: acrylamide, methacrylamide, N-alkylacrylamides, N-alkylmethacrylamides, N,N-dialkylacrylamides, N,N-dialkylmethacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyridine, N-vinylpyrrolidone, hydroxyalkylacrylates, hydroxyalkylmethacrylates. anionic monomers selected from the group comprising monomers having a carboxylic function and their salts, including acrylic acid, methacrylic acid, itaconic acid, and maleic acid; monomers having a sulfonic acid function and their salts, including acrylamide tert-butylsulfonic acid (ATBS), allylsulfonic acid, and methylsulfonic acid, and their salts; monomers having a phosphonic acid function and their salts; cationic monomers selected from the group comprising quaternized or salted dimethylaminoethyl acrylate (ADAME); quaternized or salted dimethylaminoethyl methacrylate (MADAME); the 1954082 of 41 diallyldimethylammonium chloride (DADMAC); acrylamidopropyltrimethylammonium chloride (APTAC); methacrylamidopropyltrimethylammonium chloride (MAPTAC), - the zwitterionic monomers selected from the group comprising sulfobetaine monomers such as sulfopropyl dimethylammonium ethyl methacrylate, sulfopropyl dimethylammonium propylmethacrylamide, sulfopropyl 2-vinylpyridinium; phosphobetaine monomers such as ethyl trimethylammonium ethyl methacrylate phosphate; carboxybetaine monomers. Optionally, the water-soluble polymer P may comprise at least one LOST or UCST group. According to general knowledge, a LOST group is one whose solubility in water at a given concentration changes beyond a certain temperature and depending on the salinity. This group exhibits a heating transition temperature that defines its lack of affinity for the solvent. This lack of affinity results in opacification or a loss of transparency, which may be due to precipitation, aggregation, gelation, or increased viscosity of the solvent. The minimum transition temperature is called the "LCST" (Lower Critical Solubility Temperature). 1954082 of 41 Temperature). For each LCST group concentration, a heating transition temperature is observed. This temperature is higher than LCST, which is the minimum point on the curve. Below this temperature, the (co)polymer is soluble in water; above this temperature, the (co)polymer loses its solubility in water. According to general knowledge, a UCST group is one whose water solubility at a given concentration changes below a certain temperature, depending on the salinity. This group exhibits a cooling transition temperature that defines its lack of affinity for the solvent. This lack of affinity results in opacification or a loss of transparency, which may be due to precipitation, aggregation, gelation, or increased viscosity of the solvent. The maximum transition temperature is called the "UCST" (Upper Critical Solution Temperature). For each concentration of a UCST group, a cooling transition temperature is observed. This temperature is higher than the LCST, which is the minimum point on the curve. Above this temperature, the (co)polymer is soluble in water. 1954082 of 41 The water-soluble polymer P in the invert emulsion E can be linear or structured by at least one structuring agent and can be chosen from the group comprising polyethylene unsaturation monomers (having at least two unsaturated functions), such as vinyl, allylic, acrylic and epoxy functions, and (MBA), diallylamine, trialylamine, tetraallylammonium chloride, polyethylene glycol dimethacrylate or even by macroinitiators such as polyazo polyperoxides and polytransfer agents such as polymer mercaptans or also hydroxyacrylates, vinyl epoxides. The water-soluble polymer P can also be structured using controlled radical polymerization (CRP) techniques or, more particularly, RAFT (Reversible Addition Fragmentation Chain Transfer) in reverse emulsion. According to another preferred embodiment, the inverse emulsion E of water-soluble polymer P may comprise: a hydrophilic phase comprising at least one water-soluble (co)polymer P, - a lipophilic phase, - at least one interfacial polymer composed of at least one monomer of formula (I): 1954082 of 41 Formula (I) in which, Ri, R2, R3 are chosen independently from the group consisting of a hydrogen atom, a methyl group, a carboxylate group, and ZX, Z is chosen from the group consisting of C(=0)-0; C(=0)-NH; O-C(=0); NH-C(=0)-NH; NH-C(=0)-O; and a carbon chain comprising 1 to 20 carbon atoms, unsaturated or unsubstituted or unsubstituted, which may comprise one or more heteroatoms, preferably 1, 2 or 3 heteroatoms, chosen from nitrogen and oxygen, - X is a group selected from alkanolamides, sorbitan esters, ethoxylated sorbitan esters, glyceryl esters, and polyglycosides; X comprises a hydrocarbon chain, preferably comprising 6 to 24 carbon atoms, saturated or unsaturated, linear, branched or cyclic, optionally aromatic. Without wishing to be limited to any theory, the interfacial polymer obtained by polymerization of at least one monomer of formula (I) forms a coating on the interface of the hydrophilic phase and the lipophilic phase. 1954082 of 41 In general, the lipophilic phase is present as micrometric droplets dispersed and advantageously emulsified within the hydrophilic phase. The average size of these droplets is advantageously between 0.01 and 30 µm, preferably between 0.05 and 3 µm. Therefore, the interfacial polymer is located at the interface between the hydrophilic and lipophilic phases, at the level of each droplet. The interfacial polymer partially or completely coats each of these droplets. The average droplet size is advantageously measured with a laser measuring device using conventional techniques that are part of the general knowledge of skilled tradespeople. A Mastersizer-type device from Malvern can be used for this purpose. Advantageously, the interfacial polymer comprises between 0.0001 and 10%, more advantageously between 0.0001 and 5%, and even more advantageously from 0.0001 to 1%, in number of formula (I) monomers, with respect to the total number of monomers. The interfacial polymer forms a coating around the droplets that make up the hydrophilic phase. In addition to the monomers mentioned above, the interfacial polymer may comprise at least one structuring agent. Advantageously, the structuring agent is selected from the diamine diacrylamides or methacrylamides. 1954082 of 41 acrylic esters of di-, tri-, or tetrahydroxy compounds; methacrylic esters of di-, tri-, or tetrahydroxy compounds; divinyl compounds preferably separated by an azo group; diallyl compounds preferably separated by an azo group; vinyl esters of di- or trifunctional acids; allylic esters of di- or trifunctional acids; methylenebisacrylamide; diallylamine; trialylamine; tetraallylammonium chloride; divinylsulfone; polyethylene glycol dimethacrylate; and diethylene glycol diallyl ether. Preferably, the inverse emulsion E comprises from 0.5% to 5.0% by weight, the percentages being expressed by weight with respect to the weight of emulsion E, of at least one emulsifying agent, preferably selected from sorbitan esters, polyethoxylated sorbitan esters, polyethoxylated fatty acids, polyethoxylated fatty alcohols, polyesters having an average molecular weight between 1000 and 3000 daltons resulting from the condensation between poly(isobutenyl)succinic acid or its anhydride, and a polyethylene glycol, block copolymers of average molecular weight between 2500 and 3500 daltons resulting from the condensation between hydroxystearic acid and a polyethylene glycol, ethoxylated fatty amines, di-alkanol amide derivatives, 1954082 of 41 stearyl methacrylate copolymers, and mixtures of said emulsifying agents. This emulsifying agent is added to the lipophilic phase prior to the radical polymerization reaction. Optionally, a natural or synthetic polymer (described specifically in US patent 10,647,908) may be added at the end of the radical polymerization reaction in step a) of the procedure for obtaining fluid F. Natural polymers include, for example, guar gum and its derivatives, such as hydroxypropyl guar (HPG) or carboxymethyl hydroxypropyl guar (CMHPG); and cellulosic derivatives such as carboxymethyl cellulose, hydroxyethyl cellulose, or hydroxypropyl cellulose. Advantageously, polymer P is the major component relative to the natural polymer; preferably, polymer P represents 50 to 100% by weight, preferably 70 to 100%, and most preferably 90 to 100%, with respect to the total weight of polymer P + natural polymer. Step b) of the procedure for obtaining the injection fluid F consists of distilling the inverse emulsion E to obtain a dispersion D, and therefore, the polymer P is found after distillation in the form of (solid) particles, comprising between 40 and 60% by weight of polymer P particles, less than 10% by weight 1954082 of 41 of water, and at least one hydrocarbon solvent, and the percentages are expressed by weight with respect to the weight of the dispersion D. Distillation is carried out under reduced pressure, preferably at a pressure between 20 and 250 mbar and at a temperature between 10 and 110 °C. Preferably, in the injection fluid of the invention, the polymer P is in the form of (solid) particles. Preferably, the synthetic water-soluble polymer particles P in the dispersion D have an average size between 0.01 µm and 100 µm, more preferably between 0.1 µm and 5 µm. In the present invention, average size is understood to mean the average diameter of the particles. The particle size analysis is performed according to conventional techniques known to the trade. An example of an apparatus for measuring the average particle diameter is the Mastersizer from Malvern Instruments. At the end of the distillation and, consequently, before step c) of the injection fluid F procedure of the invention, between 0.2 and 10% by weight (the percentages are expressed by weight relative to the weight of the dispersion D) of at least one inverting agent is preferably added to the dispersion (D). Preferably, the agent 1954082 of 41 of investment is chosen from among the ethoxylated nonylphenols having from 4 to 10 ethoxylations; the ethoxylated / propoxylated alcohols having preferably one ethoxylation / propoxylation comprising from 12 to 25 carbon atoms; the ethoxylated tridecyl alcohols; the polyethoxylated fatty acids, the poly(ethoxylated / propoxylated) fatty alcohols; the ethoxylated sorbitan esters; the polyethoxylated sorbitan laurate; the polyethoxylated castor oil; the heptaoxyethylated lauryl alcohol; the polyethoxylated sorbitan monostearate; the polyethoxylated cetyl ether alkylphenols; the ethylenealkyl aryl ether polyoxides; the N-cetyl-N-ethyl morpholinium ethoxysulfate; the sodium lauryl sulfate; the condensation products of fatty alcohols with ethylene oxide; the condensation products of fatty amines with 5 molar equivalents or more of ethylene oxide; the ethoxylated triestyrylphenols;Ethylene oxide condensates with polyhydric alcohols partially esterified with fatty chains, as well as their anhydrous forms; amine oxides; alkyl polyglucosides; glucamide; phosphate esters; alkylbenzene sulfonic acids and their salts; water-soluble surfactant polymers; and mixtures of several of these inversion agents. 1954082 of 41 Step c) of the injection fluid procedure F consists of diluting the dispersion D with 1% to 15% by weight of an aqueous solution S containing between 20 and 60% salts, preferably between 25 and 45%, the percentages being expressed by weight with respect to the weight of the dispersion D. The solution S is, preferably, a brine solution. Preferably, at least some of the water in solution S is extracted from the distillate of emulsion E. Advantageously, the salts in aqueous solution S are alkali or alkaline earth or ammonium salts, or organic salts, or a mixture of these salts. Most preferably, the salts are chosen from sodium chloride, ammonium sulfate, ammonium thiosulfate, ammonium chloride, choline chloride, monosaccharide salts, or a mixture of these salts. After step c) of the procedure for obtaining fluid F, other compounds known to the trade can be added, such as those cited in document SPE 152596, for example: - Biocides to prevent bacterial growth, particularly sulfate-reducing bacteria that can form viscous masses reducing surface areas. Glutaraldehyde, for example, is the most effective. 1954082 of 41 used, or also formaldehyde or isothiazolinones, and / or - Oxygen reducers such as ammonium bisulfite to prevent the destruction of other components by oxidation, and corrosion of injection tubes, and / or - Anti-corrosion additives to protect the tubes against oxidation from residual amounts of oxygen, such as N,N-dimethylformamide, and / or - Lubricants such as oil distillates, and / or - Iron chelating agents such as citric acid, EDTA (ethylenediamine tetraacetic acid), phosphonates, and / or - Anti-scaling products such as phosphates, phosphonates, polyacrylates or ethylene glycol. Therefore, the present invention also relates to a method for preparing an injection fluid F comprising the following steps: a) An inverse emulsion E is prepared by radical polymerization comprising between 15% and 40% by weight of a synthetic water-soluble polymer P with a weight-average molecular weight greater than or equal to 1 million daltons, between 20% and 60% by weight of water, and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of emulsion E, b) The inverse emulsion E is distilled to obtain a dispersion D comprising between 40 and 60% by weight of 1954082 of 41 polymer particles P, less than 10% by weight of water and at least one hydrocarbon solvent, and the percentages are expressed by weight with respect to the weight of the dispersion D, c) Dispersion D is diluted with 1% to 15% by weight of an aqueous solution S comprising between 20% and 60% by weight of salts, and the percentages are expressed by weight with respect to the weight of dispersion D. The steps of the procedure are as described above. A second aspect of the invention also relates to a hydraulic fracturing procedure for underground reservoirs of unconventional oil or gas comprising the preparation of an injection fluid F as described above, dissolving it in salt water, and injecting said fracturing fluid F into an underground formation. The injection is performed under pressure in order to create fractures distributed throughout the production wells. Prior to its injection into the underground formation, the injection fluid F obtained by the procedure of the invention is placed in solution in salt water to have a polymer concentration between 0.01 and 10 g / L in this salt water. 1954082 of 41 Salt waters can be prepared with seawater or, advantageously, with monovalent and / or polyvalent salts, or combinations thereof. Examples of salts include, without limitation, salts of sodium, lithium, potassium, aluminum, ammonium, phosphate, sulfate, magnesium, barium, nitrate, and other inorganic salts and their mixtures. Salt waters preferably contain at least one of the following elements: sodium chloride, calcium chloride, sodium bromide, calcium bromide, barium chloride, magnesium chloride, zinc bromide, sodium formate, and potassium formate. Preferably, the salt water used for the preparation of injection fluid F contains more than 70,000 ppm of salts and, preferably, more than 100,000 ppm of salts; preferably, the brine contains from 70,000 to 350,000 ppm of salts, preferably from 100,000 to 350,000 ppm. Preferably, the divalent ratio R+ = mass ratio: divalent salts / total salts is greater than or equal to 0.20 and even more preferably, R+ > 0.25. Preferably, for the injection of injection fluid F into the underground formation, at least one proppant is added before or after it is dissolved in salt water. 1954082 of 41 The proppant may be selected without restriction from sand, ceramic, bauxite, glass beads, and resin-impregnated sand. Preferably, it constitutes 0.5 to 40%, more preferably 1 to 25%, and even more preferably 1.5 to 20% by weight of the total weight of the injection fluid F for hydraulic fracturing. Optionally, before, during or after the creation of the fractures, at least one oxidizing compound and / or at least one surfactant compound is injected into the reservoir. Injecting a surfactant eliminates the rock's wettability, while injecting an oxidizing compound destroys the copolymer. In both cases, the injection restores a fluid viscosity close to that of water. Examples of oxidizing compounds include bleach (aqueous solution of sodium hypochlorite), hydrogen peroxide, ozone, chloramines, persulfates, permanganates, and perchlorates. The chemical nature of the surfactant(s) is not critical. They may be anionic, nonionic, amphoteric, zwitterionic, and / or cationic. Preferably, the surfactant(s) of the invention carry an anionic charge. 1954082 of 41 Preferably, the surfactant compounds used are selected from anionic surfactants and their zwitterions selected from the group comprising derivatives of alkyl sulfates, alkyl ether sulfates, aryl alkyl sulfates, aryl alkyl ether sulfates, alkyl sulfonates, alkyl ether sulfonates, aryl alkyl sulfonates, aryl alkyl ether sulfonates, alkyl phosphates, alkyl ether phosphates, aryl alkyl phosphates, aryl alkyl ether phosphates, alkyl phosphonates, alkyl ether phosphonates, aryl alkyl phosphonates, aryl alkyl ether phosphonates, alkyl carboxylates, alkyl ether carboxylates, aryl alkyl carboxylates, aryl alkyl ether carboxylates, aryl alkyl ether carboxylates, aryl alkyl carboxylates, aryl alkyl alkyl carboxylates, alkyl polyethers, aryl alkyl polyethers... An 'alkyl chain' is defined as a chain of 6 to 24 carbon atoms, branched or unbranched, with or without multiple motifs, which may optionally include one or more heteroatoms, for example, O, N, or S, preferably 1, 2, or 3 heteroatoms. An 'arylalkyl chain' is defined as a chain of 6 to 24 carbon atoms, branched or unbranched, which includes one or more aromatic rings and may optionally include one or more heteroatoms, for example, 1, 2, or 3 heteroatoms, preferably O, N, or S. 1954082 of 41 The most commonly used surfactants, for reasons of cost, stability and availability, are of the sulfonate or sulfate type, which come in the form of alkali metal or ammonium salts. Finally, a last aspect of the invention relates to a friction reduction procedure during a hydraulic fracturing operation of an underground reservoir of unconventional oil or gas, comprising the preparation of a fracturing fluid F as described above, dissolving it in salt water, and injecting said fracturing fluid into an underground formation. Reducing friction allows for decreasing or eliminating losses related to friction during the injection of the fracturing fluid. EXAMPLES OF IMPLEMENTATION OF THE INVENTION The following examples illustrate the invention without limiting its scope. The proportions of the different compounds are given as a percentage by weight with respect to the final weight of the emulsions. Example 1 - Preparation of an inverse emulsion The one of polymer P1 1954082 of 41 An aqueous phase is prepared with 42.1 g of an acrylamide solution (50% by weight in water), 9.1 g of acrylic acid, 10.1 g of a soda solution (50% by weight in water), 0.49 g of a diethylenetriaminepentaacetic acid solution (40% by weight in water), 0.02 g of a tert-butyl hydroperoxide solution (70% by weight in water), 0.006 g of sodium hypophosphite, and 9.134 g of water. An organic phase is prepared by mixing 20.1 g of an oil (Exxsol® D120 S) with 2.3 g of sorbitan monooleate, 0.5 g of 5 times ethoxylated sorbitan monooleate, and 5 g of a surfactant polymer. The aqueous phase is added to the organic phase, mixing under shear to form an emulsion. The emulsion is then degassed with a nitrogen flow for 30 minutes, while maintaining the temperature at 20 °C. After this time, 0.75 g of sodium metabisulfite solution (0.01 wt% in water) is injected for 90 minutes. The polymerization temperature is maintained between 40 and 55 °C. Residual monomers are reacted by adding 0.4 g of sodium bisulfite solution (40 wt%). 1954082 of 41 In this way, an inverse emulsion is obtained which contains 33% by weight of a P1 copolymer of acrylamide and sodium acrylate. Example 2 - Preparation of a DI dispersion of polymer P1 The inverse emulsion of polymer P1 obtained in Example 1 is heated to 90 °C in a reduced atmosphere (100 millibars) to evaporate the water and lighter oil fractions. This yields a DI dispersion containing 55.5 wt% polymer P1. This dispersion contains less than 10% water. Example 3 (counter-example) - Preparation of an F1 injection fluid from polymer P1 An inversion agent, ethoxylated fatty alcohol (Lutensol TO89®), is added to the DI dispersion up to 10% by weight. This results in an injection fluid F1 containing 50% by weight of polymer P1. Example 4 - Preparation of an F2 injection fluid from polymer P1 The DI dispersion obtained in example 2 is diluted by adding 18% of an aqueous solution saturated in sodium chloride and 10% of inversion agent (Lutensol TO89®). 1954082 of 41 In this way, an F2 injection fluid is obtained that contains 40% by weight of polymer P1. Example 5 - Preparation of an F3 injection fluid from polymer P1 The DI dispersion obtained in Example 2 is diluted by adding 18 wt% of an aqueous solution saturated with ammonium chloride and 10 wt% of an inversion agent (Lutensol TO89®). This yields an injection fluid F3 containing 40 wt% of polymer P1. Example 6 - Preparation of an F4 injection fluid from polymer P1 The DI dispersion obtained in Example 2 is diluted by adding 18 wt% of an aqueous solution saturated with ammonium thiocyanate and 10 wt% of an inversion agent (Lutensol TO89®). This yields an injection fluid F4 containing 40 wt% of polymer P1. Example 7 - Preparation of an F5 injection fluid from polymer P1 The DI dispersion obtained in example 2 is diluted by adding 18 wt% of an aqueous solution saturated with ammonium sulfate and 10% of inversion agent (Lutensol). 1954082 of 41 TO89®). In this way, an F5 injection fluid is obtained that contains 40% by weight of polymer P1. Example 8 - Preparation of an F6 injection fluid from polymer P1 The DI dispersion obtained in Example 2 is diluted by adding 18 wt% of an aqueous solution saturated with ammonium thiosulfate and 10 wt% of an inversion agent (Lutensol TO89®). This yields an F6 injection fluid containing 40 wt% of polymer P1. Investment tests The injection fluids F1 (comparative) and F2 to F6 (according to the invention) are placed in solution according to two different protocols. Protocol 1 (direct addition of injection fluids into a brine) Prepare synthetic seawater by dissolving 30 g of NaCl and 3 g of CaC12 in 1000 mL of water. Inject X g of dispersion into Y mL of synthetic seawater at 20 °C, under stirring (with the help of three paddles) - 500 rev / min. Where X is 5 and Y is 495 for the F1 dispersion. 1954082 of 41 Where X is 6.25 and Y is 493.75 for the dispersions F2 to F6. It is stirred for 20 minutes, and a solution of 5 g / L in polymer P1 is then obtained. The viscosity of this solution is then measured using a Brookfield viscometer at 25 °C with an LVT type module at 30 rev / min. Protocol 2 (addition of injection fluids to the water, then addition of salts) X g of dispersion is injected into Y mL of deionized water at 20 °C under stirring - 500 rev / min. Where X is 5 and Y is 478.5 for the F1 dispersion. Where X is 6.25 and Y is 477.25 for the dispersions F2 to F6. It is stirred for 20 minutes, then 15 g of NaCl and 1.5 g of CaC12 are added to the solution. It is stirred for 10 minutes, and a solution of 5 g / L in polymer P1 is then obtained. The viscosity of this solution is then measured using a Brookfield viscometer at 25 °C with an LVT type module at 30 rev / min. Experimental results 1954082 of 41 Injection Fluid Concentration P1 by weight (%) Salt in brine (S) Viscosity (cP) protocol 1 Viscosity (cP) protocol 2 F1 50 - 89 235 F2 40 NaCl 180 245 F3 40 NH4Cl 160 240 F4 40 NH4SCN 100 235 F5 40 (NH4)2SO4 165 240 F6 40 (NH4)2S2O3 195 245 Table 1: Viscosity of 5 g / L solutions of Pl polymer in synthetic seawater. Following protocol 2, regardless of the injection fluid, the resulting viscosity is 240 centipoise ± 5. Polymer P1 is rapidly released in deionized water. Subsequent addition of salts does not induce any further differences between the various viscosities. However, protocol 2 is not applicable to field applications, as polymer dissolution is carried out directly in brines. According to protocol 1, it is observed that the injection fluid F1 (counterexample) generates very little viscosity (89 cP). Using injection fluids F2 to F6, the viscosity of the P1 polymer solutions in seawater is higher. The P1 polymer in these fluids 1954082 of 41 injection is released more easily in seawater. Therefore, the procedure for preparing the injection fluids according to the invention allows for improved release of the polymer in the brine. about the 1954082 of 41 G. BREUER - 30525624826 Digitally signed by PORTALTRAMITES - INPI Date: 2022.09.13 10:15:23 -03:00 Reason: Digitally Signed by the INPI Location: Buenos Aires, Argentina 1954082

Claims

1. Injection fluid F for hydraulic fracturing, characterized in that it comprises a synthetic water-soluble polymer P with a weight-average molecular weight greater than or equal to 1 million daltons, prepared according to a process comprising the following successive steps: a) an inverse emulsion E comprising between 15% and 40% by weight of polymer P, between 20% and 60% by weight of water and at least one hydrocarbon solvent is prepared by radical polymerization, the percentages being expressed by weight with respect to the weight of emulsion E, b) the inverse emulsion E is distilled to obtain a dispersion D comprising between 40% and 60% by weight of polymer P particles, less than 10% by weight of water and at least one hydrocarbon solvent, the percentages being expressed by weight with respect to the weight of dispersion D, c) the dispersion D is diluted with from 1% to 15% by weight of an aqueous solution S comprising between 20% and 60% of salts,and the percentages are expressed in weight with respect to the weight of the dispersion D. 11 Claims follow,