METHOD FOR INHIBITING WATER PERMEATION IN A WELL EXTRACTING A HYDROCARBON FLUID FROM AN UNDERGROUND RESERVOIR.

Abstract

The present invention relates to a method for inhibiting water permeation in a well extracting hydrocarbon fluid from an underground reservoir, comprising: - supplying a water-in-oil emulsion comprising: - a continuous oil phase, - a discontinuous aqueous phase comprising a plurality of particles of at least one hydrogel comprising at least one cationic polymer; - placing said water-in-oil emulsion in contact with said underground reservoir. The present invention also relates to a treatment fluid for hydrocarbon fluid extraction wells comprising the aforementioned water-in-oil emulsion and the related preparation process.

Description

METHOD FOR INHIBITING WATER PERMEATION IN A WELL EXTRACTING A HYDROCARBON FLUID FROM AN UNDERGROUND RESERVOIR FIELD OF INVENTION The present invention relates to a method for inhibiting water permeation in a well for extracting a hydrocarbon fluid from an underground reservoir. BRIEF DESCRIPTION OF THE INVENTION In particular, the present invention relates to a method for inhibiting water permeation in a well extracting hydrocarbon fluid from an underground reservoir. This method comprises injecting a treatment fluid into the reservoir containing at least one chemical compound capable of swelling by selectively adsorbing reservoir water (i.e., formation water) present therein, thereby modifying the local permeability of the reservoir and blocking the permeability of further water into the extraction well. The treatment fluid is formulated as a dispersion of an aqueous phase in a continuous oil phase. This formulation causes the injected compound to interact primarily, or even exclusively, with the reservoir water, and not with irreducible water, thus not affecting the mobility of the hydrocarbon fluid. For the purposes of this description, the term "hydrocarbon fluid" means a fluid containing hydrocarbons or consisting primarily of hydrocarbons, in a gaseous, liquid, or gas-liquid state, of natural origin, occurring in a subsurface or submarine rock formation, such as mineral oil or natural gas. Mineral oil may optionally contain water in dispersed form. Hereinafter, in this description, the terms mineral oil and oil are used interchangeably. For the purposes of this description, the term irreducible water means the fraction of water present in the pores of a rock formation containing a hydrocarbon fluid, or in the spaces between the rock grains that make up this formation; irreducible water, retained in the formation mainly by the effect of surface tension forces, is not substantially removed during the extraction of the hydrocarbon fluid from the formation. For the purposes of this description, the term reservoir water means the fraction of water present in a rock formation containing a hydrocarbon fluid, which can be removed from the formation in association with the extracted hydrocarbon fluid. Reservoir water (or formation water, as an alternative term) can form, for example, by infiltration of water from an aquifer located near the reservoir, or by injections of water or steam into the subsurface to displace the fluid toward the production well. The presence of water in association with a hydrocarbon fluid extracted from an underground reservoir is a problem with a major economic impact in the field of oil extraction, and in general in the oil and gas industry. Extracting a hydrocarbon fluid mixed with water reduces the efficiency of MA / I / U»U4UD extraction of the fluid itself, increases the costs and dimensions of the equipment needed for water separation, increases the overall costs of fluid extraction and, finally, raises the problem of disposal of separated water, which is contaminated by hydrocarbons. The extraction of water along with the hydrocarbon fluid from an oil well, in addition to causing frequent interruptions in extraction operations to allow the implementation of measures to contain water permeation, in some cases can be of such magnitude that it leads to the early closure of the well, thus preventing the complete exploitation of the oil field (for example, when the oil field is located near an aquifer). BACKGROUND OF THE INVENTION Several techniques are known in the prior art for reducing water extraction from an oil well. One such technique involves injecting chemical compounds, such as polymers, gels, and foams, into the reservoir rock formation. These compounds form a water-impermeable mechanical barrier, blocking the preferential pathways of water within the rock formation toward the extraction well. The mechanical barrier can be achieved by reacting two or more reagents, injected separately, in situ (within the underground formation) to form a water-impermeable barrier compound. The methods known in the state of the art for inhibiting water permeation in a well extracting a hydrocarbon fluid from an underground reservoir have several drawbacks. First, the reducing effect of water permeation is short-lived. This leads to frequent interruptions in extraction activity to allow for additional injections of treatment fluid into the reservoir, with a consequent reduction in production capacity. Secondly, the compounds injected according to the methods of the previous technique have poor selectivity towards reservoir water. These compounds can also interact with irreducible water, or even with water dispersed or emulsified in oil, also causing a reduction in the mobility of the hydrocarbon fluid and, therefore, in its extraction performance. To overcome the aforementioned drawbacks, in application WO 2016 / 166672 the applicant described a treatment fluid containing hydrogel particles of micrometric or nanometric sizes. This treatment fluid comprises a dispersion or emulsion in an organic solvent of a copolymer formed by at least one acrylic monomer (met) and at least one comonomer comprising at least one ethylene unsaturation and at least one polyoxyethylene chain. This treatment fluid is highly effective in controlling water permeation inhibition in hydrocarbon fluid extraction wells, thanks to the high selectivity of the microgels and nanogels for water. Despite the excellent performance shown, the effectiveness of the hydrogels described in WO 2016 / 166672 is influenced by the salinity of the water present in the reservoir. In fact, it has been observed that the aforementioned hydrogels exhibit a high swelling capacity, i.e., swelling by water absorption, when the water salinity is high. MA / I / uaumjo within the range of 10 - 80 g / l. In waters with higher salt content (salinity > 80 g / l), hydrogels tend to absorb little water or to expel the water already absorbed. An additional drawback of known hydrogel-based treatment fluids is the not always effective adhesion of the hydrogel particles to the reservoir rock surface. In fact, in some cases, especially when reservoir fluids are produced at high pressure, hydrocarbon production operations performed after well treatment with the aforementioned hydrogel-based treatment fluids may also involve the extraction of the hydrogels themselves. Therefore, it is desirable to have treatment fluids capable of ensuring more durable and tenacious placement of the hydrogel polymeric material within the treated formation. In view of the prior art, the applicant has set the main objective of overcoming, at least in part, the drawbacks highlighted above of the methods known in the prior art. DETAILED DESCRIPTION OF THE INVENTION Within this purpose, an objective of the present invention is to provide a method for inhibiting water permeation in a hydrocarbon fluid extraction well, which effectively reduces the amount of water extracted along with the hydrocarbon fluid, thus mitigating the inconveniences related to the activities of separating water from the hydrocarbon fluid, and the disposal of water contaminated by hydrocarbons. A second objective of the present invention is to provide a method for inhibiting water permeation in a hydrocarbon fluid extraction well that can be used effectively in reservoirs characterized by rock formations that have different geological characteristics (e.g., porosity, presence of fractures, etc.). An additional objective of the present invention is to provide a method for inhibiting water permeation in a hydrocarbon fluid extraction well, which can be applied in the presence of reservoir water having salinity within a wide range of values, the method being effectively applied, in particular, even in the presence of fresh water or water with a high saline content. The applicant has now discovered that these and other objectives, which will be further illustrated in the following description, can be achieved using a treatment fluid comprising a micrometric or nanometric dispersion of an aqueous phase in petroleum, wherein the discontinuous aqueous phase comprises particles of a hydrogel comprising chains of a cationic polymer, obtained for example from monomers containing at least one cationic group (for example, a primary, secondary, tertiary, or quaternary ammonium group). In fact, it has been observed that the presence of cationic groups on the polymer leads to the formation of hydrogels based on cationic polymers with a high swelling capacity relative to water. Advantageously, the water absorption and retention properties of these hydrogels are little affected by the degree of salinity of the water, particularly when the MA / I / uaumjo salinity is due to the presence of divalent cations (e.g., Ca2+, Mg2+), which more strongly affect the performance of state-of-the-art hydrogels. Surprisingly, hydrogels containing cationic polymers also bond more strongly to carbonate rocks, probably due to electrostatic interactions between the positive charges of the polymer and the negative charges present on the surface of the carbonate rocks. Once placed within the reservoir, the materials according to the present invention thus modify the permeability of the rock formation in a more stable and lasting manner than prior art hydrogels. The hydrogels described in this document, in addition to having a high water absorption capacity, are stable under the temperature and salinity conditions of water typical of an oil or natural gas reservoir (e.g., temperature within the range of 50-90°C). In particular, water-swelling hydrogels can withstand prolonged contact with water with a high saline content without undergoing significant structural degradation. Therefore, according to a first aspect, the present invention relates to a method for inhibiting water permeation in a well for extracting a hydrocarbon fluid from an underground reservoir, comprising: - supplying a water-in-oil emulsion comprising: - a continuous oily phase, - a discontinuous aqueous phase comprising water and a plurality of particles of at least one hydrogel comprising at least one cationic polymer, wherein said cationic polymer does not contain anionic units / groups; - Place said water-in-oil emulsion in contact with said underground reservoir. In accordance with a second aspect, the present invention relates to a treatment fluid for hydrocarbon fluid extraction wells comprising a water-in-oil emulsion comprising: - a continuous oily phase, - an aqueous discontinuous phase comprising a plurality of particles of at least one hydrogel comprising at least one cationic polymer, wherein said cationic polymer does not contain anionic units / groups. This treatment fluid is effective in the present method that allows reducing the water cut in water shut-in operations in a well extracting a hydrocarbon fluid from an underground reservoir. According to another aspect, the present invention relates to a process for preparing a water-in-oil emulsion comprising: - a continuous oily phase, - a discontinuous aqueous phase comprising a plurality of particles of at least one hydrogel comprising at least one cationic polymer, MA / I / UUU4UO said process comprises the following sequential stages: - supply a continuous oily phase comprising at least one oily fluid; - supplying a discontinuous aqueous phase comprising water, at least one monomer having at least one cationic group and, optionally, at least one comonomer; - emulsify said discontinuous aqueous phase in said continuous oily phase in the presence of at least one enzyme-active agent, and at least one radical polymerization initiator, forming free radicals to polymerize said monomer having at least one cationic group, and optionally said co-monomer. For the purposes of this description and the claims, the verb "understand" and all terms derived from it, as used herein in the description and the claims, also include the meaning of the verb "consist of" and terms derived from it. The numerical limits and ranges expressed in this description and the appended claims also include the numerical value or values ​​mentioned. Furthermore, all values ​​and sub-ranges within a numerical limit or range shall be deemed to be specifically included as if explicitly stated. For the purposes of this description, the term water-in-oil emulsion (also called inverse emulsion) means a dispersion comprising at least two immiscible phases. These immiscible phases include a continuous oily phase (also called the external phase) and a discontinuous aqueous phase (also called the internal phase). The discontinuous aqueous phase is dispersed in the continuous phase as droplets, if the phase is primarily liquid, as during the preparation of the treatment fluid, or as particles, if the aqueous phase is primarily gelled, as in the case of the treatment fluid obtained after polymerization. The term droplet or particle is used herein with reference to discrete portions of the discontinuous phase in the continuous phase, without any implication regarding the shape, size, or other characteristics of the particles.These droplets or particles, according to the present invention, are also defined as micrometric or nanometric with reference to their sizes less than 1 mm and greater than 1 pm, or greater than 10 nm and up to 1 pm, respectively. For the purposes of this description, a hydrogel particle (or droplet) is a particle or droplet comprising a three-dimensional structure (network) of hydrophilic polymer chains that are substantially insoluble in water. This three-dimensional structure may be a colloidal hydrogel in which water is the dispersion medium. In the treatment fluid according to the present invention, these discrete hydrogel droplets or particles, which make up the emulsion defined herein as water-in-oil, preferably comprise a minimal amount by weight of water, more preferably less than or equal to the amount by weight of the cationic polymer. In this way, it is possible to produce a hydrogel with a high polymer concentration that exhibits significant swelling once placed in the desired position in the reservoir. ML / i / uyu-4uo The method according to the present invention allows increasing the extraction efficiency of a hydrocarbon fluid, such as mineral oil or natural gas, preferably mineral oil, from an underground reservoir. The method according to the present invention can be used advantageously to improve the extraction efficiency of both a liquid fluid, such as hydrocarbon oil, and a gaseous fluid, such as natural gas. The method according to the present invention is based on placing within the reservoir at least one water-in-oil emulsion containing a plurality of hydrogel particles comprising at least one cationic polymer capable of selectively interacting with reservoir water, absorbing it into its three-dimensional structure. Swelling of the hydrogel after water absorption prevents, or at least slows down, its permeation from the hydrocarbon fluid into the extraction well. The method of the invention can be applied to rock formations with different geological characteristics. In particular, the method is suitable for reducing water permeation in predominantly fractured rock formations, or predominantly porous rock formations. Furthermore, the method of the invention is effective even with waters with a relatively high salinity, up to 150 g / l. The inverse water-in-oil emulsion according to the present invention comprises at least one continuous oil phase in which a discontinuous aqueous phase containing the aforementioned cationic polymers is dispersed. The water-in-oil emulsion according to the present invention does not provide the use of any self-reversing agent, such as a sulfosuccinate prosthetic agent. The continuous oil phase can comprise any oily fluid suitable for this purpose. The continuous oil phase's function is to transport the hydrogel particles within the rock formation until they come into contact with the reservoir water, passing through any petroleum or hydrocarbon oil that may be present. The oily fluid usable for the purposes of the present invention is substantially insoluble in water and soluble or partially soluble in petroleum. The term substantially insoluble in water means that the oily fluid has a solubility in water at 25°C less than or equal to 5 g / L, preferably less than or equal to 1 g / L. The term partially soluble in oil or petroleum means that the oily fluid has a solubility in oil or petroleum at 25SC equal to or greater than 100 g / l. Preferably, the oily fluid is in a liquid state within the temperature range of use in extraction wells, particularly within the range of -5°C to 90°C. The oily fluid may be polar or, preferably, non-polar. Preferred examples of oily fluids usable for the purposes of the present invention are: C6-C25, more preferably C10-C15, aliphatic or aromatic hydrocarbon solvents (e.g., kerosene); amides with a total number of carbon atoms from 7 to 25; alcohols with MA / I / UUU4UO a total number of carbon atoms from 7 to 25; ethers with a total number of carbon atoms from 7 to 25, (for example, diesel ether, dioctyl ether, diphenyl ether); esters with a total number of carbon atoms from 7 to 25; ketones with a total number of carbon atoms from 7 to 25. Oily hydrocarbon fluids are particularly preferred, such as oily fluids on the market under the name LAMIX 30®, (mixture of C11-C14 hydrocarbons containing n-alkanes, isoalkanes, cyclic hydrocarbons (aromatic hydrocarbon content less than 2% by weight of the mixture)) and Versalis E-solv G®, (mixture of aliphatic and aromatic hydrocarbons). Other examples of oily fluids suitable for the purpose of the present invention are: naphtha, kerosene cuts, diesel and biodiesel cuts, aromatic solvents such as xylene, toluene and tetralin. The continuous oil phase may comprise a mixture of two or more oily fluids. The choice of oily fluid may depend on several factors, such as the polarity of the hydrocarbon fluid to be extracted, the environmental compatibility of the oily fluid, and other factors. A person skilled in the art, also with the help of this description, can select an oily fluid suitable for the specific application of the present invention. In one embodiment, the oily fluid may be present in the water-in-oil emulsion in an amount within the range of 50% to 99% by weight of the water-in-oil emulsion. In one embodiment, the continuous oil phase may be present in a weight ratio to the discontinuous aqueous phase within the range of 50:50 to 95:5. The discontinuous aqueous phase comprises a plurality of particles of at least one hydrogel comprising water and at least one cationic polymer. Preferably, the cationic polymer comprises at least one monomeric unit corresponding to a water-soluble monomer having at least one polymerizable ethylene unsaturation, and at least one cationic group, preferably an ammonium group. Preferably, the ammonium group mentioned above is an -N+-R1R2R3 group, wherein R1, R2, and R3, whether the same or different, are H or a C1-C4 alkyl group. The terms monomer and corresponding monomeric unit, as used herein and in the claims, refer to polymerizable compounds and the corresponding structural units derived from them after polymerization, which join together to form a polymer (or a copolymer if formed from different monomers or composed of different monomeric units). In the polymerization of ethylenically unsaturated monomers by the polyaddition mechanism, the monomer and the corresponding monomeric unit have the same pure formula. The cationic monomers usable for the formation of polymeric hydrogels according to the present invention are preferably selected from water-soluble salts of [2-(methacryloyloxy)ethyl]trimethylammonium, 2-(acryloyloxy)ethyltrimethylammonium, and mixtures thereof. The preferred water-soluble salts are halides, more preferably chlorides or bromides. Cationic polymers can be cationic homopolymers or cationic copolymers. MA / t / ZUZ I / UUU4UO In a preferred embodiment, cationic polymers are cationic copolymers obtained from one or more cationic monomers and one or more (hydrophilic comonomers) without cationic groups. The use of hydrophilic comonomers without cationic groups allows modulation of the hydrophilic properties of the cationic polymer, and therefore of the hydrogel, without introducing an excessive number of positive charges into the polymer chain, which could destabilize the emulsion. In one embodiment, the hydrophilic comonomer comprises at least one ethylene unsaturation and at least one polyoxyethylene chain. For example, the hydrophilic comonomer can be the compound that has the following formula (I) CH2=CRi-CO-X-(CH2CH2O-)n-R2 (I) where: Ri is H or CH3; R2 is selected from: H, C1-C4 alkyl or an acrylate group COCR3=CH2 where R3 is H or CH3; X is 0 or NH; n is an integer within the range 0 - 500, preferably within the range 0 - 200, even more preferably within the range 4-100. In a preferred embodiment, in the above formula (I) X is an oxygen atom, the comonomer being therefore acrylic or methacrylic acid, or a (poly)oxyethyl ester of said acids. In another preferred embodiment, in formula (I) above, X is an NH group, the comonomer being an acrylamide monomer. In a particularly preferred embodiment, the comonomer of formula (I) has only one ethylenic unsaturation, i.e., in the comonomer of formula (I) R1 is CH3, R2 is selected from H and C1-C4 alkyl, X is O or NH, and n is an integer within the range 4-50. In another preferred embodiment, the comonomer of formula (I) is a difunctional monomer comprising at least two ethylenic unsaturations. Preferably, the comonomer of formula (I) has a molecular weight within the range of 200 Da - 10000 Da, more preferably within the range of 200 Da - 5000 Da, even more preferably within the range of 200 Da - 3000 Da. In a particularly preferred embodiment, the hydrophilic comonomer is selected from: poly(ethylene glycol) methyl ether acrylate, poly(ethylene glycol) methyl ether methacrylate, acrylamide, methacrylamide and mixtures thereof. Poly(ethylene glycol) methyl ether acrylate, or poly(ethylene glycol) methyl ether methacrylate, preferably have a molecular weight in the range of 200 to 10000 Da, preferably in the range of 200 to 5000 Da, more preferably in the range of 200 to 3000 Da. In the present description, the molecular weights of the polymers are expressed as the weight average value (Mw), which can be determined, for example, by gel permeation chromatography (GPC). Preferably, the ratio between the total weight of the hydrophilic comonomers and the sum of the MA / 1 / uyu-4uo weight of cationic monomers and optional comonomers is within the range of 1% to 50%, preferably within the range of 3% to 40%, even more preferably within the range of 5% - 35%. For the purposes of this description and the appended claims, unless otherwise stated, the total weight of the cationic monomers and optional comonomers does not include the weight of any crosslinking agent. Hydrogel particles can have an average diameter within a wide range of values. For example, in one embodiment, the hydrogel particles can have an average diameter within the range of 1 to 1000 micrometers, preferably within the range of 5 to 500 micrometers, and more preferably within the range of 10 to 200 micrometers. For the purposes of this description, hydrogels with particles of these sizes are also referred to as microgels. The sizes of the microgels are comparable to the sizes of the fractures in fractured rock formations. Therefore, the microgels according to the present invention can be advantageously used to inhibit water permeation in a well located in a fractured rock formation. In another embodiment, the hydrogel particles can have an average diameter within the range of 10 to 500 nanometers, more preferably within the range of 50 to 300 nanometers. For the purposes of this description, hydrogels with particles of these sizes are also called nanogels. Therefore, nanogels according to the present invention can be advantageously used to inhibit water permeation in a well located in porous rock formations, where the formation pores have average sizes on the order of nanometers. The average particle diameter of the microgels and nanogels mentioned above can be determined by dynamic light scattering (DLS) measurements or, in the case of microgels, also by a compound microscope. The water-in-oil emulsions according to the present invention can be prepared using methods and devices known in the art. In particular, the microgels can be prepared by reverse suspension polymerization or reverse miniemulsion polymerization. In one embodiment, reverse suspension polymerization can be achieved by emulsifying an aqueous discontinuous phase comprising water and at least one cationic monomer in an oily continuous phase comprising at least one oily fluid, in the presence of at least one surfactant and at least one radical polymerization initiator. In the presence of the polymerization initiator and the enzyme-active agent, the monomer and comonomer react and form copolymer particles that remain enclosed within the droplets that form the discontinuous phase of the emulsion. The initiator for radical polymerization is preferably a water-soluble or water-dispersible compound. Examples of initiators that can be used for the purposes of the present invention include: halogen atom molecules, hydroperoxides, azo compounds, and ΜΛ / t / ZUZ I / U»U4UD persulfates. In order to obtain an inverse emulsion in which the hydrogel polymer particles have an average size of the order of 1 to 1000 micrometers (microgels), it is preferable to use thermally active radical polymerization initiators, that is, compounds that, after an increase in temperature, decompose forming free radicals capable of initiating the polymerization reaction of the monomers and comonomers, if any. The polymerization reaction initiated by thermally active initiators is preferably carried out at a temperature within the range of 30°C to 120°C depending on the type of initiator used, preferably at a temperature less than or equal to 90°C to avoid degradation of the polymer chains. To obtain an inverse emulsion in which the hydrogel polymer particles have an average size within the range of 10 to 500 nanometers (nanogels), it is preferable to use redox polymerization initiators. Redox initiators comprise two compounds capable of reacting with each other through an oxidation-reduction reaction, generating the radicals necessary to initiate the polymerization reaction. An example of a redox pair that can be used as a polymerization initiator is the persulfate / metabisulfite ion pair. The polymerization reaction initiated by a redox couple preferably takes place at a temperature within the range of 0 to 50°C, more preferably from 0 to 30°C. In general, the total concentration of the polymerization initiator is within the range of 0.1% to 10% by weight with respect to the weight of the monomers involved in the polymerization. In the case of microgels, the initiator is preferably added to the aqueous phase at a concentration in the range of 0.1% - 2.5% by weight with respect to the weight of the monomers involved in the polymerization. In the case of nanogels, preferably each of the two initiators of the redox pair is added to the respective continuous oil phase, and the discontinuous aqueous phase, at a concentration within the range of 1.0% - 3.0% by weight of the initiator referred to with respect to the weight of the phase to which it is added. Reverse suspension polymerization, or reverse mini-emulsion polymerization, is carried out in the presence of at least one emulsifying agent to stabilize the emulsion. The emulsifying agent can be included in the continuous phase, the discontinuous phase, or both phases. Preferably, the emulsifying agent is a testosterone-active agent. Preferably, the emulsifying agent is added at least to the continuous oil phase. To regulate emulsion stability by adding prostaglandins, two or more prostaglandins with different HLB (hydrophilic-lipophilic equilibrium) values ​​can be advantageously used. By varying the weight ratio of the prostaglandins in the formulation, the desired HLB value can be achieved. Preferably, the HLB value of an inverted emulsion containing prostaglandins is within the range of 3 to 15. For microgel preparation, the HLB value is preferably within the range of 3 to 9. For nanogel preparation, the HLB value is preferably within the range of 5 to 10. ML / I / uaumjo The surfactants used are preferably non-ionic surfactants, since the absence of electrical charges in this type of surfactant prevents its interaction with the cationic groups of the polymer, favoring the stability of the emulsion. The preferred examples of non-ionic testagents usable for the purpose of the present invention are: polysorbate 80 (hydrophilic testagent, HLB 15, for example, TWEEN80®), and sorbitan monooleate (HLB 4.3, for example, SPAN80®). The emulsifying agents are present in the invert emulsion preferably at a total concentration within the range of 1.0% - 30% by weight with respect to the weight of the invert emulsion, preferably within the range of 2.5% - 20% by weight. To obtain crosslinked hydrogels, the invert emulsion may also contain at least one crosslinking agent, which is preferably added to the discontinuous aqueous phase. Crosslinking agents known in the art that are suitable for crosslinking the cationic monomers and comonomers used for the purposes of the present invention may be used without particular limitations. Generally, the crosslinking agents are compounds having two or more ethylenic unsaturations. The preferred crosslinking agents are: N,N'-methylene-bis-acrylamide, ethylene glycol dimethacrylate, divinylbenzene, poly(ethylene glycol) diacrylate, 1,4-butanediol diacrylate, trimethylpropane triacrylate, 1,4-bis(4-vinylphenoxy)butane, bis(2-methacryloyl)oxyethyl disulfide. The degree of crosslinking of the copolymer can be varied by regulating the concentration of the crosslinking agent in the formulation. Preferably, the ratio between the total weight of the crosslinking agent and the total weight of the cationic monomers is within the range of 0.1% to 5%, preferably within the range of 0.2% to 1.0%. The emulsification phase of the discontinuous phase and the continuous phase can be carried out using homogenizing devices known in the state of the art, such as mechanical agitators (e.g. static mixer), sonicators (e.g. ultrasonic sonicator), or by high-pressure mechanical stirring. In the case of microgels, the emulsification phase is preferably carried out by mechanical agitation (reverse suspension polymerization). In the case of nanogels, the emulsification phase is preferably carried out with the help of ultrasound (reverse miniemulsion polymerization). Additional additives may be present in the water-in-oil inverse emulsions according to the present invention, provided they do not adversely interfere with the stability or other properties of the emulsions themselves. Examples of such additives include wetting agents, thickening agents, weighting agents, stabilizers, bactericides, corrosion inhibitors, oxidizers, and the like. Further information on reverse suspension or miniemulsion polymerization methods can be found, for example, in: - Dispersion polymerization in polar solvents, SAENZ, JM; ASUA, JM (JOURNAL MA / t / ZUZ I / uaumjo OF POLYMER SCIENCE, PART A-POLYMER CHEMISTRY; vol. 33 (1995), p. 1511-1521; - Superabsorbent polymeric materials: a review. Zohuriaan-Mehr, Mohammad J.; Kabiri, Kourosh; IRANIAN POLYMER JOURNAL; vol. 17 (6) (2008), p. 451-477. As stated, the inverse emulsion that includes the hydrogels according to the present invention can be used as a treatment fluid to modify water permeability in a reservoir where the rock formation is mainly porous or fractured. Without intending to refer to any particular theory, in the case of nanogels, it is assumed that a possible mechanism of action is the following: The nanogel particles containing the cationic polymer are sized to match the pore sizes of the rock formation and are transported within these pores. Thanks to the substantial miscibility of the oily fluid with the hydrocarbon oil, the discontinuous-phase particles containing the cationic polymer can migrate through the latter, if present in the rock formation, until they reach the reservoir water without undergoing significant alteration. Contact of the treatment fluid with water causes the inversion or collapse of the inverted emulsion or dispersion, thus releasing the nanogel or microgel particles, which then begin to absorb water and swell. This swelling causes a considerable increase in volume (up to 10 times the initial volume), resulting in compression and immobilization within the pores and fractures of the rock formation. This blocks or significantly slows the flow of the aqueous phase and its potential ascent to the extraction well. This creates an effective barrier to the passage of water. The applicant has also surprisingly discovered that the hydrogels of the present invention, characterized by a cationic polarity, are able, in the swollen form, to bond more firmly to the rock surface with which they come into contact, thus forming a barrier that is more resistant to pressure thrusts and, therefore, more stable with respect to the stresses to which the formation is subjected during reservoir production operations. Since emulsion inversion requires the discontinuous phase droplets to come into contact with a relatively high amount of water, contact of the droplets with irreducible water (present at the oil-oil interface in a discontinuous form and in a much smaller quantity than reservoir water), or with any water dispersed or emulsified in the oil, does not cause the release of the nanogel. Therefore, the water-in-oil emulsion containing the nanogels acts selectively towards reservoir water, being active only at points in the rock formation where the water / oil ratio is sufficiently high. In the case of invert emulsions containing microgels, the mechanism of action in the underground reservoir could be the following: Due to their larger size compared to nanogels, microgel particles have a tendency to settle after a certain period of time if they are not kept under agitation. MA / I / U»U4UD in the emulsion. Once placed in the underground reservoir, the microgel particles, of sizes compatible with the sizes of the fractures in the rock formation, settle through the continuous phase until they penetrate the aforementioned fractures, passing through any oil present, until they reach the interface between these and the water. During settling through the oil, the hydrogel particles remain substantially unchanged, not interacting, during the time required for settling, with any irreducible water or with any water present in the oil in dispersed or emulsified form. Once they have come into contact with the reservoir water, the hydrogel particles exert their absorbent action on the bulk water with which they come into contact. Even in the case of emulsions containing microgels, the release of the cationic polymer occurs selectively only at points in the reservoir where reservoir water is present. This is believed to be possible because the water dispersed or emulsified in the oil is not present in sufficient quantity to activate the emulsion breaking process—that is, to penetrate the micelles within which the microgels are enclosed. Taking into account the above, the expert in the field can appreciate the advantages derived from the use of inverse emulsions according to the present invention. In general, the reverse emulsions described herein can be used as treatment fluids in the drilling, completion and maintenance phases of extraction wells. In particular, the aforementioned emulsions can be used to inhibit water permeation in an extraction well as described herein, both before starting hydrocarbon fluid extraction operations and when the well is already in production, i.e., when the reservoir is being exploited. In particular, the method for inhibiting water permeation in an extraction well can be advantageously applied to so-called mature extraction wells, i.e., wells that have now reached the limit of production capacity, which are characterized by the extraction of significant amounts of water in association with the hydrocarbon fluid. The placement of the inverse emulsion in a reservoir, for example, can be achieved with the equipment and according to the techniques known in the oil extraction industry sector. The placement of the inverse emulsion in the reservoir can be done either through the hydrocarbon fluid extraction well, or through other wells generally present in an oil field, such as wells for the injection of steam, water or other fluids (the so-called injection wells), into the subsurface. Therefore, the reverse emulsions and the method according to the present invention can be used in the context of secondary and tertiary activities for the recovery of a hydrocarbon fluid, both in water block interventions (water cut treatment) and in rock formation treatments (shaping treatment). The amounts of invert emulsion to be injected into the underground formation may vary MA / t / ZUZ I / uaumjo widely in accordance with the specific geological formation of the deposit. The amount of invert emulsion to be injected can be easily determined by the expert in the field based on the geological characteristics of the deposit and simple routine experimental tests, as is usually done in this sector. The placement of the water-in-oil emulsion containing the cationic hydrogels can be advantageously preceded by the injection of a first aliquot of an oily fluid, preferably the same oily fluid (or mixture of oily fluids) used for the preparation of the continuous phase of the aforementioned water-in-oil emulsion. Equally advantageous, the placement of the invert emulsion in the reservoir can be followed by the placement of a second aliquot of oily fluid to facilitate the penetration of the water-in-oil emulsion into the rock formation. At the end of the invert emulsion placement and possibly the first and second aliquots of the oily fluid, hydrocarbon fluid extraction from the well can be started or resumed. Preferably, before proceeding with hydrocarbon fluid extraction by injecting a displacement fluid, a sufficient waiting period (shut-in) is observed to allow the invert emulsion to release the hydrogel polymer particles once they come into contact with the reservoir water, thus achieving the desired effect of inhibiting water mobility. If necessary, the extraction of hydrocarbon fluid can be interrupted to perform further injections of the treatment fluid, in order to obtain an additional increase in the productivity of the extraction well. The inverse emulsions according to the present invention can be prepared, if necessary, by diluting a concentrated water-in-oil emulsion with oil to the desired concentration. The concentrated water-in-oil emulsion may have a lower oil-to-water ratio than the oil-to-water ratio desired for the final application. The following embodiment examples are provided for the sole purpose of illustrating the present invention and should not be construed in a way that limits the scope of protection defined by the appended claims. EXAMPLE 1 - Preparations of inverse water-in-oil emulsions containing cationic microgels Water-in-oil emulsions containing cationic microgels were prepared by reverse suspension polymerization according to the following procedure: An oily continuous phase was prepared by mixing, with mechanical stirring, LAMIX 30 as an oily fluid and a mixture of the commercial non-ionic prosthetic agents SPAN80 and TWEEN80. The weight ratio between the two prosthetic agents was selected to cause the polymerization reaction at the desired HLB value. In the specific example of an HLB value equal to 6, the SPAN80 active ingredient was used with a mass concentration, referring to the sum of the two active ingredients, equal to 84%. An aqueous discontinuous phase was prepared by dissolving a cationic monomer (chloride of) in water, using an ultrasonic sonicator and maintaining the temperature below 50°C. MA / t / ¿U¿ I / UaU4UO [2-(methacryloxy)ethyl]trimethylammonium - MADQUAT), a crosslinking agent (N,N'-methylenebis(acrylamide) - MBA) and optionally a methacrylate comonomer of (poly(ethylene glycol) methyl ether of molecular weight 500 Da (PEGMEMA 500), or 2000 Da (PEGMEMA 2000)). An aqueous solution of 2,2'-azobis(2-methylpropianimidine) dihydrochloride (AAPH), (thermally active radical polymerization initiator), was prepared separately, using a minimal amount of water sufficient to dissolve the compound. The continuous oil phase and the discontinuous aqueous phase were mixed in a reactor with a volume of 2 liters, heated by a thermostatically controlled oil bath. Mixing was carried out using a mechanical stirrer. The reactor was equipped with a water-cooling jacket to remove the heat generated during the polymerization reaction. During polymerization, the reactor was maintained under a constant flow of nitrogen to remove air from its interior. The weight ratio between the discontinuous aqueous phase and the total weight of the water-in-oil emulsion was selected to be 16% for the PEG2 sample and 18% for the PEG4 and PEG11 samples. The polymerization reaction was initiated by adding the AAPH initiator solution drop by drop to the reaction mixture, which had been previously heated to the polymerization temperature of 70°C or 80°C. The reaction time was selected to be either 2 hours or 2.5 hours. Table 1 below shows the compositions of the prepared reverse microgel emulsions. Table 1. Composition of microgel emulsions MA / I / uaumjo MADQUAT sample (%)a PEGMEMA 500 (%)a PEGMEMA 2000 (%)a MBA (%)a AAPH (%)c Surfactants HLB 1 (A4)d 100 -- — 0.35 0.5 7.0 6 2 (PEG2)e 95 -- 5 0.35 0.5 5.0 4.3 3 (PEG4)e 90 -- 10 0.35 0.5 5.0 4.3 4 (PEG11)e 92.5 7.5 — 0.35 0.5 5.0 4.3 a: percentage by weight with respect to the weight of MADQUAT + PEGMEMA comonomers; b: percentage by weight relative to the total weight of the emulsion; c: percentage by weight with respect to the total weight of comonomers MADQUAT + PEGMEMA + MBA; d: polymerization temperature = 80°C; polymerization time 2.5 hours; e: polymerization temperature = 70°C; polymerization time 2.0 hours. EXAMPLE 2 Preparation of reverse water-in-oil emulsions containing cationic nanogels Water-in-oil emulsions containing cationic nanogels were prepared by reverse miniemulsion polymerization according to the following procedure: An oily continuous phase was prepared by mixing Eni LAMIX 30 as an oily fluid under mechanical stirring, and a mixture of the commercial non-ionic prosthetic agents SPAN80 and TWEEN80. The weight ratio between the two prosthetic agents was selected to cause the polymerization reaction at the desired HLB value. In the specific example of an HLB value of 10, the SPAN80 reagent was used at a bulk concentration, referring to the sum of the two reagents, of 47%. An aqueous discontinuous phase was prepared by dissolving in water, with the aid of an ultrasonic sonicator and maintaining the temperature below 50°C, a cationic monomer ([2(methacryloxy))ethyl]trimethylammonium chloride - MADQUAT), a crosslinking agent (N,N'-methylenebis(acrylamide)MBA), and ammonium persulfate as a first initiator of the redox initiator pair, ammonium persulfate (APS) / sodium metabisulfite (SMBS). After conditioning the continuous oil phase in an ice bath (T = approximately 0–5 sC), the discontinuous aqueous phase was added to the continuous oil phase while maintaining the mixture of the two phases under sonication. Then, an aqueous SMBS solution was added dropwise to the mixture to initiate the polymerization reaction (polymerization time 50 minutes). Table 2 below shows the compositions of the prepared reverse nanogel emulsions. Table 2. Composition of nanogel emulsions MA / t / ZUZ I / uaumjo MADQUAT sample (%)a MBA (%)b APS (%)b SMBS (%)b Active tension (%)b HLB 5(MZ17) 35 0.35 2.5 2.5 21 10 a: percentage by weight with respect to the weight of LAMIX 30®; b: percentage by weight with respect to the total weight of MADQUAT. 3. CHARACTERIZATION OF MICROGEL AND NANOGEL EMULSIONS 3.1 FLAMMABILITY TEST The water absorption capacity of the prepared microgels was determined by measuring the average particle diameter using a compound optical microscope, before and after the swelling test. The swelling test was performed by placing a few drops of a water-in-oil emulsion into a vial previously filled with water at two different salinity levels or with Lamix 30®. The samples were allowed to stand for 24 hours to allow thermodynamic equilibrium to be reached. The samples were then observed under a microscope to determine the final size of the microgel particles. The average particle diameter and polydispersity index (PDI) of the polymer in the nanogels of sample MZ17 were determined by dynamic light scattering (DLS) measurements. The particle size distribution of the nanogels was monomodal. The results of the DLS measurements are shown in Table 5. Table 3 shows the chemical compositions of the saline waters used in the test. Table 4 shows the diameter values ​​of the microgels determined in Lamix 30® and in the different waters tested. Table 3 - Composition of saline waters ML / I / UUU4UO Na+ (g / L) Ca2+ (g / L) Mg2+ (g / L) Field A 85 5.8 0.6 Field B 85 7.9 1.5 Table 4 - Microgel Diameter Lamix (pm) Dev. Std. (pm) Field B (pm) Dev Std (pm) Field A (pm) Dev. Std. (pm) A4 10.17 2.44 35.95 11.59 39.73 10.52 PEG2 9.37 5.63 32.77 11.74 30.93 13.77 PEG4 10.42 2.07 45.72 26.18 61.86 34.69 PEG11 9,904 2,372 67.22 33,381 63,916 29,087 It has been observed that in samples exposed to Lamix 30®, the microgel sizes before and after the swelling test are substantially identical; this shows that the microgels do not swell in contact with oily fluids. On the other hand, in samples exposed to water, the microgel sizes after the swelling test are larger than the sizes of the same microgels before the test. Table 5 - Nanogel diameter Diameter (nm) Polydispersity (PDI) 5 (MZ17) 299.2 0.226 MA / I / U»U4UD 3.2 EVALUATION OF COMPATIBILITY OF MICROGEL EMULSIONS WITH PRODUCTION FLUIDS The following test was performed to evaluate the behavior of cationic microgels in contact with production fluids (formation water and hydrocarbon fluids). A 10 ml aliquot of saline water was placed in a glass container. A 2 g aliquot of oil was added. The container was sealed and placed in an oven at 85°C (to simulate the temperature at the bottom of the well). The sample was then removed from the oven and the emulsion containing the microgels was added. The tested emulsions, with different concentrations of microgel particles, were dosed into the respective containers containing water and oil in quantities such as to obtain a weight concentration of microgels equal to 26-28% of the weight of the mixture. The following waters with different salinity levels, sourced from hydrocarbon oil extraction fields, were used in the test: - Field C (total salinity: 2.3 g / 1) - Field D (total salinity: 84 g / L) - Standard seawater (total salinity: 35 g / 1) In the tests, a heavy oil was used, a hydrocarbon oil with a density between 1.012 and 1.017 g / cm3 also from a hydrocarbon oil extraction field. The glass containers holding the water and oil mixtures were placed in an oven and conditioned at 85°C. At the end of the conditioning period, the emulsion containing the microgels was added to each container in the quantities indicated above. The containers were then repeatedly inverted to thoroughly mix all the components and returned to the oven at 85°C for 24 hours. At the end of the thermal conditioning, the degree of separation of the water and oil phases, the settling of the microgels at the bottom of the container, and the volume of the container occupied by the microgels after swelling as a result of water absorption were visually assessed. All samples 2, 3, and 4 showed good separation of the water and oil phases and the settling of microgel particles with water absorption in all tests, that is, with the three aforementioned waters of varying salinity. Sample 4, in particular, showed the best results in separating the aqueous and oil phases (clearer aqueous phase and greater volume occupied by swollen microgels). Therefore, the test showed that inverse emulsions containing microgels are compatible with production fluids; in particular, their contact with these fluids does not lead to oil-water emulsification that may be present, which in a real-world situation could worsen the effectiveness of oil extraction by increasing the amount of co-produced water. The tests also show the effectiveness of the emulsions prepared according to the present invention over a very wide range of water salinity. 3.3 EVALUATION OF MICROGEL EMULSIONS WITH PRODUCTION FLUIDS IN THE PRESENCE OF CALCIUM CARBONATE The following test was performed to evaluate the effectiveness of the interaction of the inverse emulsions according to the present invention with a carbonate rock. Ten grams of solid calcium carbonate were weighed into a vial. Then, 3 grams of saline solution or 4.5 grams of standard seawater (35 g / L total salinity) were added to the vial. The 3 g amount was sufficient to completely cover the calcium carbonate (Series 1). The 4.5 g amount resulted in an excess of water (Series 2). Two milliliters of an oil phase (Field D) were slowly added to the aqueous phase. The vials were then placed in an oven and conditioned at 85°C. At the end of conditioning, the emulsion containing the microgels was slowly added to each vial in a quantity of 2 milliliters, taking care not to create turbulence. Next, the vials were placed back in the oven at 85 °C for 24 hours. Finally, a visual assessment was made to determine if the microgel particles were able to penetrate the oil phase without emulsifying it, and where these particles were positioned. After a 24-hour period, the vials were inverted to evaluate the degree of adhesion to the calcium carbonate. For comparison, the test was repeated with an inverse emulsion of microgels containing methacrylic acid copolymers (partially neutralized with NaOH) and poly(ethylene glycol) methyl ether methacrylate (HEMA-PEG, PM = 2000 Da, 42 polyoxyethylene units), prepared as described in Example 2 of WO 2016 / 166672. In the Series 1 samples supplemented with emulsions containing cationic microgels No. 2, 3, and 4, complete penetration of the microgel particles between the calcium carbonate grains was observed. This penetration was not substantially observed in the comparative sample. The observed penetration is probably attributable to the electrostatic attraction between the positive charges of the cationic microgels and the negative charges of the calcium carbonate, as well as the smaller particle sizes of the cationic microgels (around 10 micrometers) compared to the comparative microgel particles (approximately 20 micrometers). Furthermore, after inverting the vials, it was observed that samples No. 2, 3, and 4 help to compact the carbonate grains together, so that the solid phase remains firm at the bottom. ML / i / uyu-4uo of the vial even when it is turned upside down. In contrast, in the comparative sample, when the vial was turned upside down, the breakage of the calcium carbonate grains and their downward sliding was observed. The same behavior of the cationic microgels according to the invention and of comparative one was observed in the Series 2 samples that contained excess water. The test has demonstrated a greater capacity of the microgel particles of the emulsions according to the present invention to interact with carbonate rocks with respect to prior art microgel emulsions. 4. CHARACTERIZATION OF NANOGEL EMULSIONS 4.1 Test 1 - Washing of cores saturated with oil and saline water The injection capacity of sample 5, containing nanogel particles, was evaluated within a sandy medium (Berea sandstone), as was its ability to modify water permeability in a formation, by measuring flow in a porous medium. A cylindrical core, 5.09 cm long and 2.47 cm in diameter, with a porosity of 16.5%, was used for this purpose. The core was placed in a core holder under a confining pressure of 40 bar to prevent fluid leakage. The core was initially filled with synthetic seawater (salinity: 33 g / L) and heated to 40°C in an oven. The core was then washed with Lamix 30® until it reached the point where no more water was produced (core under residual water saturation). At this point, sample 5 was injected at approximately 24 times the pore volume. The core was then left to stand at 40°C for 24 hours (sealed) to allow the nanogels to act. At the end of the sealing period, the core was washed again with synthetic seawater to verify the potential water permeability reduction effect of the cationic nanogels. Sample 5 was easily injectable and no pressure increases were observed during its injection. The final wash with saline water showed a reduction in the core's water permeability compared to the water wash prior to treatment with the inverse emulsion according to the invention. The initial water permeability value was 36 mD and dropped to 1.4 mD at the end of the test, due to the desired behavior of the cationic nanogels.

Claims

1. A method for inhibiting water permeation in a well for extracting a hydrocarbon fluid from an underground reservoir, said method being characterized in that it comprises: - supplying a water-in-oil emulsion comprising: - a continuous oil phase, - a discontinuous aqueous phase comprising a plurality of particles of at least one hydrogel comprising at least one cationic polymer; - placing said water-in-oil emulsion in contact with said underground reservoir.

2. The method according to claim 1, further characterized in that said cationic polymer comprises at least one monomeric unit having at least one cationic group.

3. The method according to the preceding claim, further characterized in that said at least one cationic group is a -N+-R1R2R3 group, wherein R1, R2 and R3, whether the same or different, are H or a C1-C4 alkyl group.

4. The method according to claim 1, further characterized in that said cationic polymer comprises at least one monomer unit corresponding to a monomer selected from the water-soluble salts of [2-(methacryloyloxy)ethyl]trimethylammonium, 2(acryloyloxy)ethyltrimethylammonium and mixtures thereof.

5. The method according to the preceding claim, further characterized in that said polymer comprises at least one co-monomeric unit corresponding to a monomer selected from: poly(ethylene glycol) methyl ether acrylate, poly(ethylene glycol) methyl ether methacrylate, acrylamide, methacrylamide and mixtures thereof.

6. The method according to claim 5 above, further characterized in that the weight ratio of said co-monomeric unit and said monomeric unit is within the range of 5% - 50%, preferably within the range of 10% - 35%, even more preferably within the range of 20% - 30%.

7. The method according to claim 5, further characterized in that said poly(ethylene glycol) methyl ether acrylate or poly(ethylene glycol) methyl ether methacrylate has a molecular weight within the range of 200 to 10000 Da, preferably within the range of 200 to 5000 Da, more preferably within the range of 200 - 3000 Da.

8. The method according to claim 1, further characterized in that said cationic polymer is a crosslinked polymer.

9. The method according to claim 1, further characterized in that the continuous phase is present in a ratio to the discontinuous aqueous phase within the range of 50:50 to 95:5 by weight.

10. The method according to claim 1, further characterized in that said hydrogel particles have an average diameter within the range of 1 to 1000 micrometers. MA / I / UUU4UO 11. The method according to claim 1, further characterized in that said hydrogel particles have an average diameter within the range of 10 to 500 nanometers.

12. The method according to claim 1, further characterized in that it comprises: a. placing a first aliquot of an oily fluid, preferably having the same composition as the oily fluid of the continuous oily phase of said water-in-oil emulsion, in contact with said underground reservoir; b. placing said water-in-oil emulsion; c. placing a second aliquot of said oily fluid; d. injecting a displacement fluid to produce said hydrocarbon fluid.

13. A treatment fluid for hydrocarbon fluid extraction wells characterized in that it comprises a water-in-oil emulsion comprising: - a continuous oil phase, - a discontinuous aqueous phase comprising water and a plurality of particles of at least one hydrogel comprising at least one cationic polymer.

14. The treatment fluid according to the preceding claim, further characterized in that said cationic polymer comprises at least one monomeric unit corresponding to a monomer having at least one cationic group.

15. The treatment fluid according to the preceding claim, further characterized in that said at least one cationic group is an -N+-R1R2R3 group, wherein R1, R2 and R3, whether equal or different, are H or a C1-C4 alkyl group.

16. The treatment fluid according to claim 13, further characterized in that said cationic polymer comprises at least one monomer selected from: halogen salt of [2-(methacryloyloxy)ethyl]trimethylammonium, halogen salt of 2-(acryloyloxy)ethyltrimethylammonium and mixtures thereof.

17. A process for preparing a water-in-oil emulsion characterized in that it comprises: - a continuous oil phase, - a discontinuous aqueous phase comprising water and a plurality of particles of at least one hydrogel comprising at least one cationic polymer, said process comprising the following sequential steps: - supplying a continuous oil phase comprising at least one oily fluid; - supplying a discontinuous aqueous phase comprising water, at least one monomer having at least one cationic group and, optionally, at least one comonomer; - emulsifying said discontinuous aqueous phase in said continuous oil phase in the presence of at least one surfactant and at least one free-radical polymerization initiator to polymerize said monomer having at least one cationic group and, optionally, said comonomer.

18. A process according to the preceding claim, further characterized in that said initiator is thermally activatable, and the emulsification is carried out by means of a mechanical stirrer at a temperature equal to or higher than the activation temperature of said thermally activatable initiator.

19. The process according to claim 17, further characterized in that: - said initiator comprises at least one pair of redox initiators comprising an oxidizing initiator and a reducing initiator, one of said oxidizing initiator and said reducing initiator being incorporated into one of said continuous oil phase and said discontinuous aqueous phase, the remaining initiator being added to the water-in-oil emulsion during emulsification; - said emulsification is carried out by ultrasound.