Method for inhibiting water permeation in an extraction well of a hydrocarbon fluid

Abstract

A method is described for inhibiting water permeation in an extraction well of a hydrocarbon fluid from an underground reservoir comprising injecting a treatment fluid comprising at least one aqueous dispersion of stabilised nanoparticles, wherein the water forming said dispersion has a salinity lower than 4 g / 1 NaCl and wherein said nanoparticles comprise or consists of at least one anionic copolymer comprising a plurality of repeating units deriving from : ( a ) one or more acrylate monomers formed from C1-C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof; and from (b ) one or more monomers in the form of salificable aliphatic chain unsaturated carboxylic acids selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof.

Description

[0001] METHOD FOR INHIBITING WATER PERMEATION IN AN EXTRACTION WELL

[0002] OF A HYDROCARBON FLUID

[0003] The present invention relates to a method for inhibiting, or at least signi ficantly reducing, water permeation from subterranean or subsea rock formations having a fractured or porous matrix, in an extraction well of a hydrocarbon fluid of an underground reservoir, in particular a mature reservoir .

[0004] More particularly, the present invention relates to the aforesaid method for inhibiting the permeation of water, in particular high-salinity water, during the extraction of the hydrocarbon fluid, for example during water shut-of f operations , by inj ecting into the reservoir a treatment fluid comprising at least one compound capable of selectively absorbing / reacting with the reservoir water present therein, thereby blocking the permeation of said water towards the extraction well . The treatment fluid is formulated in such a way that the inj ected compound only interacts with the reservoir water, thus not af fecting the mobility of the hydrocarbon fluid .

[0005] For the purposes of the present description, the expression "hydrocarbon fl uid" refers to a naturally-derived fluid containing hydrocarbons or mainly hydrocarbons , in the gaseous or liquid state or in the form of a gas-liquid mixture , present in a subterranean or subsea rock formation, such as a hydrocarbon oil or a natural gas . The hydrocarbon oil may possibly contain water in dispersed or emulsi fied form .

[0006] Hereinafter in the present description, the terms "hydrocarbon oil" and "oil" are used alternatively .

[0007] For the purposes of the present invention, "reservoir wa ter" , "forma ti on wa ter" refer to the fraction o f water present in a rock formation containing a hydrocarbon fluid that can be removed during the extraction of the fluid from the rock formation . The reservoir water can be formed, for example , by infiltration of water from an aqui fer located near the reservoir or by inj ections of water or steam in the subsoil carried out to displace the fluid towards the extraction well .

[0008] For the purposes of the present invention, the term " irreducibl e wa ter" refers to the fraction of water present in the pores of a rock formation that is not substantially removed during the extraction o f the fluid from the rock formation .

[0009] One of the maj or problems encountered in mature reservoirs during the extraction of hydrocarbons is the extraction of signi ficant quantities of excessive water along with the hydrocarbons .

[0010] Water thus produced has a negative impact on hydrocarbon production as it involves high costs for treating the extracted hydrocarbon and di sposing of the water, as well as a production decrease during the same extraction time .

[0011] Nowadays , there are substantially two techniques to mitigate water extraction : mechanical and chemical ( gels , cements or similar ) .

[0012] The mechanical method is suitable for sealing large fractures that bring water near the well .

[0013] Existing chemical techniques for selectively blocking water-only channels can be critical due to the characteristics of the well or reservoir such as high temperature , high water salinity, low porosity of the rock formation, large fractures in the carbonate matrix, etc . , and as a result , many " wa ter shut -off trea tment" applications ( actions for blocking water to reduce the production o f undesired water ) are carried out with low-performance products and they generally fail .

[0014] Various techniques are known in the state of the art for reducing or preventing the extraction of water from an oil well .

[0015] In Application WO2016 / 166672 , in the name of the Applicant , a treatment fluid containing polymeric hydrogel particles of micrometer or nanometer si ze is described . Such a processing fluid comprises a dispersion or emulsion in an organic solvent ( reverse emulsion) of an anionic copolymer consisting of at least one (meth- ) acrylic monomer and at least one unsaturated co-monomer comprising at least one polyoxyethylene chain .

[0016] Such a treatment fluid is very ef fective in inhibiting water permeation in wells for extracting hydrocarbon fluids , due to the polymer ability to react only with water by absorbing it , resulting in the polymer particles which swel l to three times their si ze : in this way, the channels and pores of the rock formation from which the water comes are "pl ugged" .

[0017] Despite the excellent performance shown, the ef ficacy of the hydrogels disclosed in W02016 / 166672 is negatively af fected by a high salt content of the water, as their swelling capacity is inversely proportional to the salinity of the water evaluated in terms o f NaCl or ionic strength : it was observed that the aforementioned hydrogels have a high swelling capacity due to water absorption when the water has a sal inity of up to 80 g / 1 NaCl . In case of water with a higher salt content ( salinity > 80 g / 1 ) , hydrogels tend to absorb little water or expel what has already been absorbed as they lose their ability to swell .

[0018] Therefore , the use of these hydrogels i s limited to a narrow salinity range of the water in the reservoir, and their use is not recommended in reservoirs with high salinity formations , e . g . greater than 80 g / 1 NaCl .

[0019] Furthermore , the chemical composition of these hydrogels limits their use in reservoirs having temperatures above 100 ° C due to the limited thermal resistance of the polymer which causes the structural degradation of the hydrogels .

[0020] Improved performance in water with a high salt content is disclosed for the treatment fluid covered by Patent Application WO2020194145A1 , which comprises a dispersion or emulsion in an organic solvent ( reverse emulsion) of a cationic polymer capable of clinging more ef fectively to rocks and creating a water barrier .

[0021] However, even for this type o f polymer, there is a stated maximum salinity limit beyond which the treatment fluid containing it loses its ef fectiveness ( 150 g / 1 NaCl as stated value and 85 g / 1 NaCl as value obtained by tests ) .

[0022] Therefore , the anionic and cationic systems of the above-described prior art are not versatile and applicable in any well , as the salinity of the water must be known precisely in order to decide which material to use .

[0023] Furthermore , the methods for synthesising hydrogels are complex as they involve the preparation of reverse emulsions wherein the polymer is carried in oil , resulting in high production costs .

[0024] It is therefore highly desirable to have available a treatment fluid for inhibiting water permeation that i s environmentally sustainable and that is ef fective at both low and high formation water salinities , in particular that is also ef fective at salinities greater than 150g / l NaCl , so that it can be used in any extraction well .

[0025] It is also highly desirable that the aforesaid treatment fluid is also ef fective at temperatures of wells above 100 ° C .

[0026] It is further highly desirable that the aforesaid treatment fluid be less susceptible to detachment due to a strong draw-down pressure o f the production well ( around 10- 20 bars ) so as to ensure a more durable and tenacious placement of the treatment fluid in the formation .

[0027] In fact , in some cases , especially in those contexts where reservoir fluids are produced at a high pressure , it is possible that the hydrocarbon fluid extraction operations , that are carried out after the well has been treated with the treatment f luids , also involve the extraction of said fluids and thus the detachment of the material acting as a water extraction barrier .

[0028] Accordingly, an obj ect of the present invention is to provide a method for inhibiting, or at least substantially reducing, water permeation from subterranean or subsea rock formations having a fractured or porous matrix, in an extraction well of a hydrocarbon fluid of an underground reservoir, said method comprising :

[0029] A) placing in contact with said reservoir, preferably by inj ection, at least one treatment fluid comprising at least one aqueous dispersion of stabili zed nanoparticles , wherein water forming said dispersion has a salinity lower than 4g / l NaCl and wherein said nanoparticles comprise , or consist of , at least one anionic copolymer comprising a plurality of repeating units deriving from :

[0030] ( a ) one or more acrylate monomers formed from Ci -C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof ; and from

[0031] (b ) one or more monomers in the form of sali ficable aliphatic chain unsaturated carboxylic acids preferably selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof .

[0032] The terms "monomer" and "repea ting uni ts" as used in this description refer, respectively, to compounds that can be polymerised as they comprise a -C=C- double bond and the corresponding structural units derived from said monomers after polymerisation, which bind together to form a copolymer .

[0033] In accordance with the present invention, the singular indefinite article one is understood to also include the meaning of at least one , unless otherwise speci fied . In the present description of the invention, unless otherwise specified, the range values include the extremes of the range.

[0034] In the present description of the invention, unless otherwise specified, the percentages (%) are by weight.

[0035] In the present description of the invention, the term "to comprise" also includes, as a special limiting case, its meaning as "to consist of".

[0036] In the present description of the invention, the term "consists essentially of" means that

[0037] - the composition or method necessarily includes the listed ingredients or steps; and that

[0038] - the composition or method is open to unlisted ingredients or steps that do not materially affect the basic and innovative properties of the composition or method .

[0039] In the present description of the invention, unless otherwise specified, the term's "part" and "parts" refer to part by weight and parts by weight, respectively.

[0040] The salinity of the water present in the dispersion of copolymer nanoparticles of step A can advantageously vary from 0 to a value lower than 4 g / 1 NaCl, preferably from 0 to 0.9 g / 1 NaCl, more preferably from 0 to 0.1 g / 1 NaCl, even more preferably the water present in the dispersion is demineralised water. In addition, the ionic strength of the water present in the dispersion of copolymer nanoparticles of step A) is equal to or lower than 0.08.

[0041] The term "ionic strength" herein refers to the total concentration of ions present in the formation water or in the water used to prepare the dispersion of the invention: this quantity therefore takes into account not only the presence of NaCl (to which salinity is related) but also the presence of bivalent ions (e.g. Ca2+, Mg2+) .

[0042] Contact of the aqueous dispersion of the invention with the formation water, which generally has an ionic strength >0.08 (as well as a salinity greater than 4g / l) , i.e. higher values than the water used in the copolymer dispersion of the present invention, causes the copolymer nanoparticles to coalesce and coagulate as they are no longer stable, forming a continuous layer of polymer film that acts as a barrier to the passage of water.

[0043] The destabilisation time of the aqueous copolymer dispersion according to the invention is governed by the ionic strength of the reservoir water: the greater the ionic strength, the shorter the time it takes for the dispersion to coagulate. See the examples.

[0044] Furthermore, for the same ionic strength, destabilisation times are also affected by the reservoir temperature: the higher the reservoir temperature, the shorter the time it takes for the dispersion to coagulate .

[0045] The aforesaid coagulation mechanism of the copolymer nanoparticles according to the present invention does not occur i f the dispersion of the present invention comes into contact with the hydrocarbon because the aqueous dispersion passes through the hydrocarbon phase without reacting ( see the examples ) and therefore the dispersion of the invention is selective to water .

[0046] Indeed, the Applicant has found that when the nanoparticles of the aforesaid negatively charged copolymer ( anionic copolymer ) , preferably stabilised in the aqueous dispersion by means of the anionic surfactant , come into contact with the positive ions present in the formation water, i . e . , in contact with water having a higher ionic strength / salinity than the water used for preparing the dispersion of the present invention, a destabilisation of the anionic copolymer particles occurs , which collapse by sticking together to form a strong and elastic rubbery fi lm that is capable of occluding the pores and small fractures present in the reservoir rock .

[0047] The monomers ( a ) of the present invention are preferably selected from methyl acrylate , ethyl acrylate , butyl acrylate , methyl methacrylate , ethyl methacrylate , butyl methacrylate , isopropyl acrylate , isopropyl methacrylate , 2- ethylhexyl acrylate , 2-ethylhexyl methacrylate , lauryl acrylate , lauryl methacrylate , stearyl acrylate , stearyl methacrylate .

[0048] The monomers (b ) of the present invention are capable o f giving rise to anions as they are sali fiable compounds in a partially or fully deprotonated form ( deprotonable compounds ) .

[0049] The polyacrylic acid - ( CH2-CHCO2H)n- ( PDA) and polymethacrylic acid - ( CH3CH-CHCO2H)n- that can be used in the present invention may advantageously have a minimum weight average molecular weight corresponding to a value of n=3 .

[0050] Generally, the polyacrylic acid and polymethacrylic acid that can be used in the present invention has a weight average molecular weight (Mw) not exceeding 5000 Dalton .

[0051] In one embodiment , the polyacrylic acid and polymethacrylic acid that can be used in the present invention has a weight average molecular weight not lower than 1000 Dalton .

[0052] In another embodiment , the polyacrylic acid and / or polymethacrylic acid that can be used in the present invention has a weight average molecular weight ranging from 1000 Dalton to 2800 Dalton .

[0053] In one embodiment , the polyacrylic acid and / or polymethacrylic acid has a weight average molecular weight of 2500 Dalton . It is understood that in the present invention, the polyacrylic acid ( PPA) and polymethacrylic acid having a molecular weight evaluated di f ferently from the above , for example a number average molecular weight , or having a weight average molecular weight (Mw) greater than 5000 Dalton, may be used as monomers (b ) without departing from the scope of the present invention .

[0054] The copolymer in nanoparticle form contained in the aforesaid dispersion usable in the method of the present invention thus comprises repeating units derived from one or more of the aforesaid

[0055] - acrylate monomers ( a ) and one or more of the aforesaid

[0056] (meth- ) acrylic acids / poly (meth- ) acrylics (b ) .

[0057] Generally, the acrylic monomer content (b ) ( or the total content of the acrylic monomers (b ) ) in the copolymer i s greater than 0 . 5% and lower than 30% by weight with respect to the weight of the copolymer, the remaining part to 100% being represented by the weight of the acrylate monomer ( a ) or of the total weight of the acrylate monomers ( a ) .

[0058] In the present aqueous dispersion, the copolymer content is a maximum of 64 % by weight with respect to the total weight of the aqueous dispersion and a minimum of 5% by weight of the total weight of the aqueous dispersion .

[0059] In one embodiment , the copolymer content in the present aqueous dispersion is between 10% by weight and 54-55% by weight with respect to the weight of said dispersion .

[0060] In a preferred embodiment , the copolymer content in the present aqueous dispersion i s between 25% and 35% by weight with respect to the weight o f said aqueous dispersion .

[0061] The copolymer present in the form of nanoparticles in the dispersion used in the method of the present invention is obtained by the polymerisation, e . g . radical , in direct emulsion ( i . e . oil-in-water ) of the two aforementioned types of monomers A) , (b ) according to techniques known to the person skilled in the art or according to a polymerisation process as will be described hereinafter .

[0062] The copolymer nanoparticles present in the aqueous dispersion that can be used in the method of the present invention advantageously have an average diameter ranging from 10 to 500 nanometres , preferably from 10 to 100 nanometres , as measured by Dynamic Light Scattering ( DLS ) : the nanometric si ze of the copolymer particles is such that the aqueous dispersion of the present invention is suitable for any type of rock reservoir as it is readily inj ectable in reservoirs having a wide range of permeability, from mDarcy to Darcy of semi- fractured reservoirs , in sandstonelike reservoirs and in carbonate- fractured reservoirs .

[0063] In the present description, the term "permeabili ty" (measured in Darcy, mDarcy) is the same term used in geology and petroleum engineering and identifies the ability of rock to allow a liquid to pass through it, depending on the porosity and fracturing of the rock.

[0064] In one embodiment of the invention, the average diameter of the copolymer nanoparticles presents in the aqueous dispersion according to the present invention is between 50-70 nanometres, preferably around 60 nanometres.

[0065] The copolymer nanoparticles contained in the aqueous dispersion used in the present method of the invention are advantageously stabilised due to the presence of at least one anionic surfactant in said aqueous dispersion.

[0066] The presence of said anionic surfactant in the aqueous dispersion of copolymer nanoparticles is preferred as it allows the nanoparticles to be stabilised in water: said at least one anionic surfactant can be selected from among the anionic surfactants known in the art of polymerisation in aqueous emulsion such as, for example, carboxylate surfactants, sulphates, phosphates, or combinations thereof.

[0067] Examples of the aforesaid anionic surfactants can be alkyl, alkylaromatic chain sulfonates (e.g. sodium dodecylbenzenesulphonate, SDBS) ; sulphates, phosphates or carboxylates with alkyl, alkylaromatic, alkyloxyethylene chain (e.g. sodium laurylethoxysulphate) .

[0068] The anionic surfactant is preferably selected from the sulphate class, more preferably sodium dodecyl sulphate (SDS) .

[0069] In one embodiment, the content of said stabilising anionic surfactant in the aqueous dispersion used in the aforesaid method may vary from 0.5% to 10% by weight with respect to the total weight of the aqueous dispersion of the present invention.

[0070] In another embodiment, the content of said stabilising anionic surfactant is in the range from 0.5% to 3.5%, preferably from 0.5% to 2%, more preferably around 1.0%, by weight with respect to the total weight of the aqueous dispersion of the present invention.

[0071] The weight average molecular weight (Mw) of the copolymer in nanoparticle form in the aqueous dispersion according to the invention is generally a high molecular weight, in the order of tens of thousands of Dalton, for example between 10,000 Dalton and 1 000 000 Dalton, preferably between 50 000 and 500 000 Dalton, more preferably between 200 000 and 350 000 Dalton.

[0072] This molecular weight can advantageously be a weight average molecular weight (Mw) and can be measured according to the prior art, e . g. by means of gel permeation chromatography (GDC) .

[0073] Alternatively, in case the measurement by means of GDC is not possible, the molecular weight can be measured by means of techniques other than GDC such as viscometry, using Mark Houwink ' s law, which links intrinsic viscosity to molecular weight according to laws known in the art , without departing from the scope of the present invention .

[0074] In the aqueous dispersion according to the invention, the final concentration of unreacted (meth- ) acrylate monomer in the polymerisation ( or unreacted (meth- ) acrylate monomers ) is lower than 500 ppm, preferably lower than or equal to 100 ppm, more preferably lower than or equal to 10 ppm, which makes the present dispersion an environmentally compatible product .

[0075] The dispersion of copolymer nanoparticles according to the present invention can be placed in contact with the reservoir by carrying out step A) before starting the extraction of the hydrocarbon fluid from an oil reservoir or when the well is already in production, i . e . when exploitation has started, preferably before starting extraction .

[0076] In particular, the method for inhibiting water permeation according to the present invention can be advantageously applied to the so-cal led "mature" extraction wells , namely wells that have now reached the limit of production capacity, which are characteri zed by the extraction of signi ficant quantities of water in association with the hydrocarbon fluid .

[0077] The step A) of positioning the treatment fluid according to the method of the present invention can be carried out with equipment and according to techniques known from the oil extraction industry, for example by inj ection .

[0078] The inj ection o f the treatment fluid into the reservoir can be carried out either through the extraction well of the hydrocarbon fluid or through the other wells generally existing in an oil field, such as the wells for inj ecting steam, water, or other fluids into the subsoil ( so-called inj ector wells ) .

[0079] The method for inhibiting water permeation according to the present invention can thus be used indi f ferently :

[0080] - as part of secondary and tertiary activities for the recovery of a hydrocarbon fluid;

[0081] - in water shut-of f treatments ;

[0082] - in conformation treatments .

[0083] Particularly preferred is the application of this method to inhibit water permeation in water shut-of f treatments .

[0084] The quantities of treatment fluid to be used in step A) of the method according to the invention may vary widely depending on the speci fic geological conformation of the reservoir .

[0085] The quantity of reverse emulsion to be inj ected can be easily determined by the person skilled in the art based on the geological characteristics o f the reservoir and simple routine experimental tests , as normally happens in thi s sector .

[0086] The method for inhibiting, or at least signi f icantly reducing, permeation according to the present invention may also provide further steps following the aforesaid step (A) .

[0087] In particular, after placing said aqueous dispersion in contact with the reservoir, for example by inj ecting a treatment fluid comprising the aforesaid aqueous dispersion, a step B ) of inj ecting a displacement fluid ( e . g . , gas , solvent , fresh water or other displacement fluids known in the art ) may possibly follow, so as to promote penetration of the treatment fluid of the present invention into the rock formation of the reservoir .

[0088] After inj ecting the treatment fluid of the invention in step A) , and possibly the displacement fluid in a subsequent step B ) , the extraction of the hydrocarbon fluid from the well may be started or resumed .

[0089] Preferably, before proceeding with the extraction of the hydrocarbon fluid, a suf ficient amount of time is al lowed for the treatment fluid to release the copolymer nanoparticles once they have come into contact with the reservoir water and to achieve the desired water mobility inhibition ef fect .

[0090] I f necessary, the extraction of the hydrocarbon fluid can be interrupted to carry out further inj ections of the treatment fluid, so as to obtain a further increase in the productivity of the extraction well.

[0091] The advantages resulting from the method of the invention which uses a treatment fluid comprising aqueous dispersions of copolymer nanoparticles in accordance with the present invention are several.

[0092] The copolymer nanoparticle dispersions of the present invention can be used in wells wherein there is a temperature (T) >100°C, e.g. a T around 120°C, unlike anionic hydrogels known in the art, as the copolymer particles of the present invention are resistant to high T because the polymer does not degrade at those temperatures.

[0093] In fact, tests were carried out with a specific latex placed in contact with a brine having a salinity of 30 g / 1 in order to destabilise the latex, then introducing the resulting mixture in an oven at 135°C and keeping it under these conditions for 30 days: at the end of the test, the polymer formed due to the destabilisation of the latex was still compact, did not soften and did not show any breakage.

[0094] Tests as described above and carried out up to 10 days, 20 days, 40 and 50 days also showed that at the end of the test, the polymer formed by the destabilisation of the latex was still compact, did not soften and did not show breakage.

[0095] In addition, the dispersions of the present invention are less sensitive to high draw-down pressures (P) , e.g. P > 20 bars , as the copolymer nanoparticles according to the invention show high adhesion to each other forming a strong rubber film and very adherent to the rock formation, unli ke the cationic and anionic polymer particles of the prior art which, being single units not bound to each other, show poor adhesion to each other and to the rock in the presence of high pressure deltas at the well opening .

[0096] A further advantage o f using a treatment fluid comprising aqueous dispersions of copolymer nanoparticles in accordance with the present invention is the fact that the present dispersion can be used in rock formations with a wide range of permeability ( from mDarcy to semi- fractured formations which have permeabilities of even > 1 Darcy) and thus in both fractured and porous matrix formations of a carbonate / sandstone nature , due to the nanometric si ze of the copolymer particles in the aqueous dispersion .

[0097] Another advantage is that the dispersions of the present invention can be used to block water with a wider salinity range from 4g / l to over 250 g / 1 NaCl , even rich in bivalent ions (high water hardness and high ionic strength) , which makes the copolymer dispersions of the present invention a product suitable for situations where it is not possible to know exactly where the water is coming from in order to be able to block with non-selective blocking materials such as cements . Yet another advantage of the present invention is that the copolymer dispersions of the invention are obtained by direct emulsion, and thus are easy to manufacture with lower production costs than those obtained by reverse emulsion .

[0098] A further advantage is the higher polymer content in the dispersion, since in the present invention the dispersion to be applied in the well is stable with a polymer content of around 35% v / v, whereas dispersions of anionic and cationic polymers of the prior art have been shown to be stable with a much lower polymer content of around 12- 18 % v / v : the higher polymer concentration in the aqueous dispersions of the present invention therefore makes the transport and storage of the treatment fluid less expensive .

[0099] The process for preparing the aqueous copolymer dispersion as defined above and used in the method of the present invention provides for the copolymerisation of the aforementioned monomers ( a ) , (b ) in water, preferably in a water having a salinity that may advantageously vary from 0 to a value lower than 4 g / 1 , preferably from 0 to 0 . 9 g / 1 , more preferably from 0 to 0 . 1 g / 1 , even more preferably demineralised / distilled water or fresh water .

[0100] In one embodiment , said copolymer can be obtained by radical polymerisation in direct emulsion ( i . e . oil-in- water ) , preferably in an aqueous emulsion using water with a salinity ranging from 0 to a value lower than 4 g / 1 NaCl , preferably from 0 to 0.9 g / 1 NaCl, more preferably from 0 to

[0101] 0.1 g / 1 NaCl, even more preferably demineralised / distilled water or fresh water.

[0102] In particular, the process for preparing the aqueous dispersion of copolymer nanoparticles as defined above, hereinafter also referred to as "latex", according to the present invention comprises the steps of

[0103] (1) adding to a water having a salinity lower than 4 g / 1, at least one monomer (a) as defined above and at least one monomer (b) as defined above, preferably in the presence of at least one anionic surfactant, to obtain an emulsion of said monomers;

[0104] (2) under stirring, sequentially adding to said emulsion obtained in step (1) at least one radical polymerization initiator;

[0105] (3) carrying out the polymerisation for a time such as to obtain a conversion of the monomers (a) , (b) of at least 90%; and optionally

[0106] (4) adding at least one radical initiator different from that of step (2) until detecting a concentration of acrylate monomer (a) (or a total concentration of acrylate monomers (a) ) lower than or equal to 500 ppm, preferably lower than or equal to 100 ppm.

[0107] The water used in step (1) of the process according to the present invention preferably has a salinity ranging from 0 to 0.9 g / 1, more preferably from 0 to 0.1 g / 1, even more preferably demineralised / distilled water, or fresh water.

[0108] The total content of monomers (a)+ (b) in the emulsion obtained in step (1) may vary from 5 wt% to 50 wt% of the total weight of the emulsion, the remaining part up to 100 consisting either of water or water containing anionic surfactant .

[0109] Step (1) can take place under mild stirring, although this is not binding for the purposes of the present invention .

[0110] Stirring in step (1) is preferred as it allows the emulsification of the discontinuous phase (monomers (a) , (b) ) and the continuous phase (water) as well as their homogenisation: such stirring, preferably at low speed, e.g. 200 rpm, can be carried out using the homogenizer devices known in the art, such as mechanical stirrers (e.g. static mixer) , high-pressure mechanical stirrers or sonicators (e.g. ultrasonic) .

[0111] The temperature of step (1) is generally room temperature, although this is not binding for the purposes of the present invention.

[0112] The anionic surfactants used in step (1) may be those previously defined, although this is not binding for the purposes of the present invention. In one embodiment, the content of said stabilising anionic surfactant in the emulsion may be in the range from 0.5% to 4%, preferably in the range from 1 to 3.5% by weight with respect to the total weight of the emulsion obtained in step (1) containing the monomers (a) and co-monomers (b) but not yet containing the polymerisation initiators.

[0113] Step (2) is preferably carried out in an inert and / or air / oxygen-deprived atmosphere (e.g. under vacuum) .

[0114] The radical polymerisation initiators that can be used in step (2) , otherwise referred to herein as redox initiators, are preferably compounds that are soluble or dispersible in water (hydrophilic initiator) .

[0115] The redox initiators that can be used in step (2) generally comprise two compounds (an oxidising initiator and a reducing initiator) that are capable to react with each other by an oxidation-reduction reaction, generating the radicals required to initiate the polymerisation reaction.

[0116] Examples of radical initiators of polymerisation in water that can be used in step (2) for the purposes of the present invention are: halogen atom molecules, hydroperoxides, azo compounds and persulphates.

[0117] In particular, ammonium persulphate, potassium persulphate, sodium persulphate, hydroxymethanesulphonic acid monosodium salt dihydrate, 4 , 4 ' -Azobis ( 4-cyanovaleric acid) , ter-Butyl hydroperoxide (TBHP) , sodium hydroxymethanesulphinate (e.g. Rongalite, Bruggolite®, formic aldehyde sulfoxylate) can be mentioned as radical initiators that can be used in step (2) .

[0118] The polymerisation reaction beginning in step (2) is preferably carried out at a temperature ranging from 0°C to 120°C, depending on the type of initiator used, so as to avoid degradation of the polymer chains.

[0119] The polymerisation reaction can be initiated by redox initiators that are active at a temperature in the range 0- 30°C or that are active at a temperature in the range 30°C- 120°C.

[0120] In step (2) , a pair of radical initiators, which are active at a temperature in the range 30°C-120°C, is preferably used.

[0121] It is also particularly preferred to accelerate the polymerisation reaction so as to speed up the conversion of the monomers (a) , (b) by using a third initiator capable of decomposing by developing heat so as to increase the temperature of step (2) without any heating, thus ensuring the activation of the pair of redox initiators added in step (2) .

[0122] In one embodiment, Ammonium Persulphate, Albite (NaAlSi3O8) and Ferrous Sulphate (FeSO are added sequentially in step (2) .

[0123] In general, the total concentration of the polymerisation initiator or initiators used in step (2) varies in the range from 0.05% to 10% by weight with respect to the weight of the monomers (a) , (b) , preferably in the range from 0.05% to 2.5% by weight with respect to the weight of the monomers (a) , (b) .

[0124] In step (3) , polymerisation can be carried out, for example, for a time of about 1 hour (at 70°C) .

[0125] In step (3) , a high conversion of the monomers takes place, which can be way over 90 %: in the event that a quantitative conversion is not achieved in step (3) , i.e. when some residual monomer (a) (or residual monomers (a) ) still remain, then it is preferable to add to the mixture obtained in step (3) another pair of redox initiators selected from those already indicated in step (2) .

[0126] An example of a radical polymerisation initiator that can be used in step (4) is the pair of redox initiators formed of sodium hydroxymethanesulphinate (formic aldehyde sulfoxylate) and TBHP (tert-butyl hydroperoxide) .

[0127] In step (4) the addition of the initiator generally takes place slowly, e.g. 9-10 ml in 45 minutes.

[0128] In step (4) , the detection of the ppm content of acrylate monomer (a) (or the sum of acrylate monomers (a) ) can be carried out by GC analysis.

[0129] Thanks to the process as defined above, an aqueous dispersion can be advantageously obtained comprising (% by weight with respect to the total weight of the dispersion)

[0130] - from 5% to 64 % of an anionic copolymer in the form of nanoparticles having an average diameter ranging from 10 to 500 nanometers , said copolymer comprising a plurality of repeating units deriving from :

[0131] ( a ) one or more acrylate monomers formed from Ci - C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof ; and from

[0132] (b ) one or more monomers in the form of sali f icable aliphatic chain unsaturated carboxylic acids selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof ;

[0133] - from 0 . 5% to 10% by weight of a stabil i zing anionic surfactant ; the remaining part up to 100 being made up of , or including, water having a salinity lower than 4g / l NaCl .

[0134] The aforesaid dispersion can also be achieved by processes known in the art without thereby departing from the scope of the present invention .

[0135] The following embodiment examples are provided merely to illustrate the present invention and should not be construed in a sense that would l imit the scope of protection defined by the claims . EXAMPLES

[0136] REACTANT AND COMPOUNDS

[0137] - Ethyl acrylate (EA) : marketed by Merck with a purity of over 98%;

[0138] - Sodium dodecyl sulphate: marketed by Roth with a purity >99.0%;

[0139] - Polyacrylic acid: marketed by Merck, and having a weight average weight (Mw) of 2500 Dalton;

[0140] - Ammonium persulphate: marketed by Merck with a purity of 100%;

[0141] - Albite : grains with a size of 1.52-4.83 mm, marketed by ThermoFisher Chemical with a purity of over 99%;

[0142] - ferrous sulphate: marketed by Roth with a purity >99.0%;

[0143] - TBHP (Tert-Butyl hydroperoxide) : 70% w / w TBHP solution in water marketed by Sigma Aldrich;

[0144] - Bruggolite® E01 (sodium hydroxymethanesulfinate) :marketed by Bruggeman Chemical;

[0145] - Euratex AS1 : mixture of polymeric substances marketed by Montaldi .

[0146] MEASURING METHODS AND CHARACTERISATIONS

[0147] Determination of residual ethyl acrylate (EA) monomer content from polymerisation reactions in aqueous solution Analysis by GC-MS (gas chromatography-mass spectrometry,

[0148] Agilent GPC220 instrument) was used to determine unreacted EA. Concentration (% weight / dispersion weight) of copolymer in the dispersion (latex)

[0149] The measurement was carried out by thermogravimetric analysis (Electronic Moisture Analyser, Sartorius-Model MAI 60 ) using a thermobalance and determining the percentage by weight of solid (polymer) by subtraction of all liquid components present in the product that have been evaporated .

[0150] Copolymer particle size

[0151] The copolymer particle s i ze was determined by instrumental Dynamic Light Scattering ( DLS ) using the Zetasi zer Ultra - Malvern instrument .

[0152] Surface Charge or Z Potential of polymer particles

[0153] This parameter determines the thermodynamic and time stability of the colloid dispersion ( latex ) ; stability i s achieved when the potential value Z is greater than - 60 mV . The instrumental technique i s Electrophoretic Light Scattering (ELS ) using the Zetasi zer Ultra - Malvern instrument .

[0154] Density

[0155] Density was measured in the temperature range 25-45 ° C with a densimeter ( instrument : Densimeter DMA 4100M - Anton PAAR) .

[0156] Dynamic viscosity profile of the dispersion (latex) S6 as such and thickened dispersion (latex) S6 (with 4 g / 1 Euratex AS1)

[0157] In order to evaluate the injectability of the latex sample into horizontal and vertical well formations and to assess whether the viscosity values are within the parameters required for water shut-off (WSO) applications, the viscosity profile at 25°C of the latex sample as such and of the same latex thickened with 4g / l thickener was evaluated using a HAAKE-MARS rotational rheometer: latex, as such, showed a Newtonian behaviour (substantially constant cP viscosity (8 cP) ) with increasing shear rate (1 / s) ) while the latex admixed with thickener (Euratex AS1) showed a non-Newtonian behaviour (decreasing cP viscosity (380-36 cP) with increasing shear rate (1-1000 1 / s) ) .

[0158] Clay swelling test

[0159] This test is performed to assess whether the fresh water included in the latex of the invention can damage the rock formation by swelling in case it contains clay. The test is performed using a reference sample of Varano clay that has a maximum swelling value in distilled water of 70% (corresponding to a 70% increase in the initial volume of the sample) . The measuring was carried out using the "Dynamic Linear Swell Meter" - OFITE instrument. A tablet (0=28.3mm; h=approx .12mm) consisting of the selected clay material (7.5 grams 80-100 mesh + 7.5 grams 100-140 mesh of Varano clay) is exposed to the test fluid circulating around the tablet at a speed of 170 rpm at a temperature of 30 ° C .

[0160] A linear, variable , and di f ferential transducer measures the change in the tablet height and data are acquired over time until this variation reaches a steady-state value . Changes in height are recorded as percentage variations from the initial si zes .

[0161] Weight average molecular weight (Mw) of the copolymer

[0162] It was measured by means o f GPC analysis with a Waters Acquity APC System instrument using DMSO as a solvent .

[0163] Example la : Preparation of Ethyl acrylate-polyacrylic acid latex (S6) and thickened latex S6

[0164] The production of the latex S 6 involves an initial step of preparing an emulsion of an ethyl acrylate (EA) monomer in distilled water stabilised by the surfactant Sodium Dodecyl Sulphate and polyacrylic acid .

[0165] The emulsion was prepared by loading the aforesaid components into a 1 L glass Buchi reactor, j acketed, capable of working under pressure or under vacuum, equipped with pressure and temperature gauges , and a stirring anchor connected to an electric motor and the discharge of reaction products to the bottom of the reactor .

[0166] The composition of the monomer emulsion that was prepared is as follows ( % by weight with respect to the total weight of the emulsion) :

[0167] - Ethyl Acrylate (EA) monomer: 33%;

[0168] - polyacrylic acid monomer: 1.22%;

[0169] - Sodium Dodecyl Sulphate (stabilising surfactant) : 2.5%;

[0170] - distilled water: remaining part up to 100%.

[0171] After loading the aforesaid components, the mixture is deprived of oxygen by removing the air and making a vacuum, and then inerted with N2 and mixed at low speed (maximum 200rpm) at room temperature (25°C) until an emulsion is obtained .

[0172] Then, the three radical initiators herein reported are added sequentially to the 500 g of emulsion prepared above to activate the polymerisation of the aforesaid monomers:

[0173] 0.01% by weight Ammonium Persulphate with respect to the weight of the emulsion;

[0174] 0.036% by weight of Albite with respect to the weight of the emulsion, and

[0175] 0.0074% by weight of Ferrous Sulphate (FeSO with respect to the weight of the emulsion.

[0176] With the addition of FeSCy, polymerisation is triggered by developing heat, which raises the temperature from 25°C to a reaction temperature of 90°C in about one minute, resulting in an increase in internal reactor pressure to 2 bars .

[0177] Samples were taken during polymerisation to determine the conversion time trend: the polymerisation reaction continued for about one hour at a temperature of 70-75°C.

[0178] After this time, a conversion greater than 99% was achieved . Then it has been proceeded by slowly adding two further

[0179] Redox initiators, hereinafter indicated, which are necessary to convert the remaining unreacted monomer (EA) into polymer: 0.11%w of a 70% TBHP solution (ter butyl hydroperoxide in demineralised water) ; - 0.078%w of Buggolite® (C-Bruggeman-formic aldehyde sulfoxylate (rodite) in demineralised water) .

[0180] The residual EA value was lower than 10 ppm.

[0181] The weight average molecular weight (Mw) of the copolymer obtained was equal to 280 000 Dalton. The latex (S6) was then submitted to a chemical-physical characterisation, obtaining the values summarised in Table 1.

[0182] Table 1: chemical-physical parameters of latex S6

[0183] The viscosity profile determined for latex S6 as such showed low rheological values, making it easily injectable in all types of formations including those with a low permeability .

[0184] Example lb: Preparation of thickened latex (S6)

[0185] Considering the low viscosity values of latex S6, the latex S6 prepared in Example la was thickened to obtain viscosity values falling within the parameters required for special WSO (water shut-off) applications.

[0186] The increase in viscosity aims to avoid that, in case of applications in horizontal and fractured wells, the latex S6 alone covers only the lower part of the hole, leaving the part above the reservoir uncovered.

[0187] The mixing of the thickener Euratex AS1 with the latex S6 was carried out in proportions such as to reach the viscosity values required by the application and it corresponds to a concentration of the thickener in the latex of 4g / l .

[0188] The viscosity profile of the latex S6 thickened as above revealed a non-Newtonian behaviour, with the following viscosity values shown in Table 2.

[0189] Example 2: Latex destabilisation evaluation at different temperatures

[0190] The latex S6 prepared in Example la was subjected to a destabilisation bulk test to evaluate the time taken for the latex solution to pass from liquid (initial state) to gel (destabilisation occurred) to which the formation of a polymeric film (strong, elastic rubber) corresponds, by evaluating the destabilisation at five different temperatures of the latex and brine sample (by placing the latex and brine samples in the oven at the given temperature) : room temperature, 65°C, 70°C, 80°C, 87°C.

[0191] Latex samples were placed in contact with aqueous salt solutions (brines) having a specific salinity measured as ionic strength (I.F.) .

[0192] The salinity range of the aqueous solutions used and their Ionic Strength (I.F.) is given in Table 3. Table 3: Destabilisation times of latex (S6) in different salinity and temperature contexts.

[0193] Table 3 shows the formation time with salt solutions

[0194] (brines) and temperatures typical of a fractured, horizontal

[0195] Italian reservoir.

[0196] As it can be seen from Table 3:

[0197] - At room temperature, the latex destabilises instantly (gel time=0) as soon as it comes into contact with brine with a salinity >92 g / 1 or F.I. >1.75;

[0198] - At reservoir temperatures of 80-87°C (typical of an Italian fractured field) latex destabilisation times are very short (40 min-20 min) even for salinities up to 12g / l; for brines with low salinities <12 g / 1, the polymer destabilises in longer times of 10 hours or more;

[0199] - By lowering the reservoir temperature by 10°C, 70°C, the polymer destabilisation time is greater than 8 days, brine always with a salinity of 12 g / 1.

[0200] The destabilisation times of the latex of the invention therefore increase as the Ionic Strength of the saline water and the temperature decrease.

[0201] Example 3: Destabilisation evaluation of thickened latex S6 at two different temperatures

[0202] Example 2 was repeated but using the thickened latex S6 (4 g / 1 Euratex AS1) prepared in Example lb, evaluating the destabilisation at room temperature and at 80°C (in an oven) of various brine samples admixed with thickened latex. The results are shown in the following Table 4 (Destabilisation times of thickened latex S6 under different salinity and temperature conditions) .

[0203] Table 4

[0204] The compari son of the data in Table 4 above with those in Table 3 of the latex as such shows that the destabilisation times at 80 ° C are accelerated in the thickened latex S 6 compared to the latex as such, particularly in water contexts with low salinity or ionic strengths around 4- 12 g / 1 . Example 4 : Destabilisation evaluation of latex S6 at 80 °C in the presence of hydrocarbons

[0205] In order to evaluate the behaviour of the latex S6 in the presence of an oil phase, the same test as described in Example 2 was repeated at 80°C, but by also adding an aliquot of a hydrocarbon (crude oil) to the test tube containing saline water and latex, in the volume proportions of 1:1:1 salt water: crude-oil: latex.

[0206] The test was carried out both in static mode, i.e. without providing energy to the test tube with the fluids, and in dynamic mode, i.e. energetically mixing the test tubes with the three fluids, oil-lattice-brines.

[0207] The following oils were used as hydrocarbons:

[0208] - a non-aromatic refining hydrocarbon, Lamix 30® (mixture of Cn-C® hydrocarbons containing n-alkanes, isoalkanes, cyclic hydrocarbons (aromatic hydrocarbon content lower than 2% by weight of the mixture) ) ;

[0209] - a crude oil typical of a fractured-horizontal Italian reservoir .

[0210] These oils were used in a 1:1 ratio by volume to latex.

[0211] STATIC TEST: Bulk testing, in static mode, of Latex ( S 6 ) , in the presence of waters having different salinities

[0212] (brines) . Latex is added last into the test tube already containing brines (at the bottom) and crude oil: it can be observed (see Figure 1) that the latex passes through the hydrocarbon phase without reacting to combine with the salty aqueous phase at the bottom of the test tube where the destabilisation of the polymer particles begins due to the presence of the salts and the effect of the 80°C temperature.

[0213] What is observed, thus, is the passing of the crude barrier by the latex without reacting, latex combining with the brine and beginning to destabilise in the manner described above.

[0214] DYNAMIC TEST: Bulk testing, in dynamic mode, of Latex (S6) , in the presence of crude oil and water with different salinities (brines) .

[0215] Latex is added to the test tube already containing brines and crude oil by vigorously mixing the tubes with the three fluids, crude-latex-brines: only for samples with F.I. > 1.75 where the latex instantly destabilises at room T, a part of the crude oil is observed (see Figure 2) to be incorporated into the rubber by the stirring vortex and the remaining crude oil still remains free to flow. In samples with brine with F.I. < 1.01 on the other hand the 2 phases, crude and brine + latex, have time to separate before the polymer destabilisation without observing any mixing between crude and polymer, the oil remains free to flow confirming that the mechanism is selective to water.

[0216] Example 5: Fluxing test of latex in Portland cores saturated with saline water, at room temperature and 80 °C

[0217] It was evaluated the injectability of: copolymer latex s6 (prepared in Example la and containing 34% by weight of copolymer - shown in Table 5 as Latex 34% a.i.) ; latex s6, 50% diluted with distilled water (containing 17% by weight of copolymer and indicated in Table 5 as Latex 17% a.i.) ; thickened latex S6 prepared in Example lb (indicated in Table 5 as Latex 34% a.i. + Euratex Asl (thickner) ) ; within a porous medium (hereinafter referred to as a "core") and their ability to reduce water permeability in a rock formation by fluxing various porous media (Portland cores) with different water permeabilities in the range from 10 to 400 mD (see table) , in order to evaluate the behaviour of latex in semi-fractured contexts in which the permeability is generally > 1 Darcy.

[0218] The test is carried out with diluted latexes to evaluate the effectiveness thereof in reducing permeability so that cost savings can be obtained.

[0219] The fluxing apparatus used consists of a system for pumping fluids that are to be injected into the core placed in a Hassle-type core-holder enclosed in a rubber sleeve to which an external pressure (generally +20 bars relative to the internal P) is imposed to prevent the flow passage between the confining chamber and the rock; the rock samples (cores) are positioned vertically and the fluids are injected from the bottom upwards.

[0220] Test pressures are measured by pressure transducers positioned on the inlet and outlet line of the core, directly connected to the metal heads on the upper and lower parts of the core.

[0221] This makes it possible to accurately measure the differential pressure AP along the core, avoiding any artefacts due to pressure drop or line clogging.

[0222] All the devices, pressure-transducers -temperature detectors and pump flow adjustment controllers, are continuously recorded by a data acquisition system.

[0223] A cylindrical Portland core (clay-free limestone) with a length of 5 cm and a diameter of 5 cm, having a porosity of 17-21%, was used for the test.

[0224] The core was initially filled with a saline water (hereinafter also referred to as brine) having a salinity of 12 g / L NaCl and an ionic strength of 0.24 (values representative of fractured, horizontal Italian reservoirs) and brought to the test temperature (80°C) to measure the initial permeability of the core to brine (Ki brine) . Filling was carried out until the core internal pressure stabilised in relation to the flow rate (saturation) .

[0225] Afterwards, the reference latex sample was injected about the pore volume (PV) of the core and left to rest, at the test temperature, for a given time (1-2 hours) (shut- in) .

[0226] At the end of the shut-in period, the core was again flushed with brine and the final permeability of the core to brine (Kf brine) was measured in order to evaluate the effect of reduced water permeability generated by the latex of the present invention.

[0227] The reduction in water permeability was calculated using the formula:

[0228] (Ki - Kf ) / Ki*100 (Ki =initial permeability; Kf=final permeability) representing the reduction in brine permeability before and after latex injection.

[0229] Ki and Kf are calculated using the following formula:

[0230] - Q is the fluid flow rate;

[0231] - k is the permeability of the porous medium;

[0232] - Ap is the pressure difference measured in two sections of the porous medium separated by a distance L along the duct ;

[0233] - p is the fluid viscosity coef ficient ;

[0234] - A is the section through which the fluid passes .

[0235] The data related to the Portland core saturated with saline water are reported in Table 5 .

[0236] Table 5 : Coreflooding results with latex in brine-saturated Portland cores

[0237] The final fluxing with saline water showed a reduction in the permeability of the core to water with respect to fluxing with water prior to the treatment with the latex of the present invention . Compare the Ki (be fore latex treatment ) and Kf ( after latex treatment ) as reported in the aforesaid table .

[0238] Example 6 : Latex fluxing test in hydrocarbon oil- saturated Berea core , at room temperature

[0239] The process of Example 5 was repeated but using a Berea core (porous medium with a high clay content ) , instead of a Portland core, and saturating it with a hydrocarbon oil

[0240] (commercially available under the name LAMIX 30®, consisting of a mixture of C11-C14 hydrocarbons containing n-alkanes, isoalkanes, cyclic hydrocarbons, with an aromatic hydrocarbon content lower than 2% by weight of the mixture) instead of saline water.

[0241] To this end, a cylindrical core with a length equal to 5 cm and a diameter equal to 5 cm, having a porosity of 20% was used.

[0242] The core was initially filled with Lamix 30 and brought to the test temperature (25°C) to measure the initial permeability of the core to Lamix 30 (Ki) .

[0243] Filling was carried out until the core internal pressure stabilised in relation to the flow rate (saturation) .

[0244] Next, latex S6 from Example la was injected but diluted to 15% by weight of polymer (indicated in Table 6 as Latex 15% a.i. ) .

[0245] The data for the Berea core saturated with Lamix 30 are reported in Table 6.

[0246] Table 6 : Results of coreflooding test with latex in

[0247] Berea core saturated with hydrocarbon oil

[0248] Fluxing of the ( diluted) latex in the hydrocarbon- saturated porous medium ( Lamix 30 ) confirmed the nonreactivity of the latex of the present invention in that an almost unaltered final permeability of the porous medium compared to its initial permeability is noted, demonstrating that the latex allows the oil to flow .

[0249] Example 7 : Clay swelling test

[0250] A Varano clay sample was submitted to the swelling test .

[0251] The swelling observed with the latex S 6 prepared in Example la was 30% : this value , which is much lower than the 70% known in fresh water, may be presumably attributed to the external coating of the clay particles by the polymer contained in the latex, which partially prevented the waterclay interaction, thus limiting the swelling.

[0252] Example 8 : Draw-down test

[0253] Latex inj ectivity was evaluated by measuring the pressure increase exerted during latex inj ection into the porous medium with respect to the baseline of the initial brine,

[0254] The draw-down test at different deltas P (otherwise also referred to as pressure-t ightness test) was carried out by injecting a mixture consisting of the polymeric dispersion S6 (i.e. latex prepared in Example la) and salt water with a salinity of 30 g / 1 (volume ratio 1:1) inside steel cores (drilled internally) via a transfer cylinder and pressurised to 20 bars.

[0255] The cores were placed in an oven at 85°C for 24 hours to simulate latex destabilisation in a well.

[0256] For the tightness test at different deltas P: an internal pressure (test pressure) was imposed on the core (filled with the destabilised latex S6) increased in steps of 10 bar at a time and maintained for 8 / 12 hours.

[0257] The destabilised polymer held up to a pressure of 20 bars .

[0258] Considering the smooth steel core surface, the max P value of 20 bars can be considered as an underestimate when considering the rough, irregular surface of the reservoir rock .

Claims

CLAIMS1 . Method for inhibiting water permeation from subterranean or subsea rock formations having a fractured or porous matrix, in an extraction well of a hydrocarbon fluid of an underground reservoir, said method comprising :A) placing in contact with said reservoir, preferably by inj ection, at least one treatment fluid comprising at least one aqueous dispersion of nanoparticles , wherein water forming said dispersion has a salinity lower than 4g / l NaCl and wherein said nanoparticles comprise , or consist of , at least one anionic copolymer comprising a plurality of repeating units deriving from :( a ) one or more acrylate monomers formed from Ci -C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof ; and(b ) one or more monomers in the form of sali ficable unsaturated carboxylic acids having aliphatic chain selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof .2 . Method according to claim 1 , wherein the monomers ( a ) of the present invention are selected from methyl acrylate , ethyl acrylate , butyl acrylate , methyl methacrylate , ethyl methacrylate , butyl methacrylate , isopropyl acrylate , isopropyl methacrylate , 2-ethylhexylacrylate, 2-ethylhexyl methacrylate, lauryl acrylate, lauryl methacrylate, stearyl acrylate, stearyl methacrylate.

3. Method according to claim 1 or 2, wherein the acrylic monomer content (b) (or the total content of the acrylic monomers (b) ) in the copolymer is greater than 0.5% and less than 30% by weight with respect to the weight of the copolymer, the remaining part up to 100% being represented by the weight of the acrylate monomer (a) or of the total weight of the acrylate monomers (a) .

4. Method according to any one of the preceding claims, wherein the copolymer in the form of nanoparticles has a weight average molecular weight (Mw) comprised in the range from 10 000 Dalton to 1 000 000 Dalton, preferably between 50 000 and 500 000 Dalton, more preferably between 200 000 and 350 000 Daltons.

5. Method according to any one of the preceding claims, wherein the copolymer content in the aqueous dispersion varies from 5% to 64% by weight with respect to the total weight of the dispersion.

6. Method according to any one of the preceding claims, wherein the polymer nanoparticles have an average diameter ranging from 10 to 500 nanometers, preferably from 10 to 100 nanometers, as measured by Dynamic Light Scattering (DLS) .

7. Method according to any one of the precedingclaims, wherein at least one stabilizing anionic surfactant is present in the dispersion, preferably in quantities ranging from 0.5% to 10% by weight with respect to the total weight of the dispersion.

8. Method according to any one of the preceding claims, wherein step A) is carried out before starting the extraction of the hydrocarbon fluid from an oil reservoir.

9. Method according to any one of the preceding claims, wherein the quantity of treatment fluid to be placed in said step A) is determined according to the geological conformation of the reservoir.

10. Method according to any one of the preceding claims, wherein said step A) is followed by a step B) of injection of a displacement fluid to favor the penetration of said treatment fluid into the rock formation of the reservoir .

11. Method according to any one of the preceding claims, wherein at the end of step A) of placing of the treatment fluid and possibly of the displacement fluid in a subsequent step B) , the extraction of the hydrocarbon fluid from the well is started or resumed.

12. Method according to any one of the preceding claims, wherein in said step A) the treatment fluid comprises, or is constituted of, at least one aqueous dispersion comprising (% by weight with respect to the totalweight of the dispersion)- from 5% to 64% of an anionic copolymer in the form of nanoparticles having an average diameter ranging from 10 to 500 nanometers, said copolymer comprising a plurality of repeating units deriving from:(a) one or more acrylate monomers formed from Ci -C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof; and(b) one or more monomers in the form of salificable unsaturated carboxylic acids having aliphatic chain selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof;- from 0.5% to 10% by weight of a stabilizing anionic surfactant ; the remaining part to 100 being constituted of, or including, water having a salinity of less than 4 g / 1 NaCl .

13. Treatment fluid for extraction wells of hydrocarbon fluids comprising an aqueous dispersion of a copolymer as defined in any one of the preceding claims from 1 to 9, 12.

14. Process for preparing the aqueous dispersion of anionic copolymer nanoparticles as defined in any one of claims from 1 to 9, 12 comprising the steps of:(1) adding at least one monomer (a) and at least one monomer (b) as defined in the preceding claims to a water having a salinity lower than 4 g / 1, preferably in the presence of at least one anionic surfactant, to obtain an emulsion of said monomers;(2) under stirring, sequentially adding at least one radical polymerization initiator to said emulsion obtained in step (1) ;(3) carrying out the polymerization, preferably at a temperature ranging from 0°C to 120°C, for a time such as to obtain a conversion of the monomers (a) , (b) of at least 90%; and optionally(4) adding at least one radical initiator different from that used in step (2) until detecting a concentration of acrylate monomer (a) (or a total concentration of acrylate monomers (a) ) lower than or equal to 500 ppm, preferably lower than or equal to 100 ppm.

15. Process according to claim 14 , wherein in step (2) the initiator is a combination of ammonium persulphate, albite (NaAlSi3O8) and ferrous sulphate (FeSO , added sequentially .

16. Process according to claim 14 or 15, wherein in step (4) the initiator is a combination of sodium hydroxymethanesulfinate (formic aldehyde sulfoxylate) andTBHP (tert-butyl hydroperoxide) .

17. Aqueous dispersion comprising (% by weight with respect to the total weight of the dispersion)- from 5% to 64% of an anionic copolymer in the form of nanoparticles having an average diameter ranging from 10 to 500 nanometers, said copolymer comprising a plurality of repeating units deriving from:(a) one or more acrylate monomers formed from Ci - C24 aliphatic esters of acrylic acid or methacrylic acid or combinations thereof; and from(b) one or more monomers in the form of salificable unsaturated carboxylic acids having aliphatic chain selected from acrylic acid, methacrylic acid, polyacrylic acid, polymethacrylic acid or combinations thereof;- from 0.5% to 10% by weight of a stabilizing anionic surfactant ; the remaining part to 100 being constituted of, or including, water having a salinity of less than 4 g / 1 NaCl .

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