Method for the enhanced recovery of hydrocarbons by sequential injection of polymer compositions

Abstract

The present invention relates to a method for the enhanced recovery of hydrocarbons, involving flushing a subterranean formation with an injection fluid comprising a polymer P1 in salt water A1, then with an injection fluid comprising a polymer P2 in salt water A2, the polymers P1 and P2 being distinct.

Description

[0001] METHOD FOR THE ENHANCED RECOVERY OF HYDROCARBONS BY

[0002] SEQUENTIAL INJECTION OF POLYMER COMPOSITIONS

[0003] Field of the invention

[0004] The present invention relates to a method for the enhanced recovery of hydrocarbons (petroleum and / or gas) using a sequential injection sequence of different injection fluids having distinct compositions (nature of the polymer, salinity of the solution).

[0005] Prior art

[0006] The majority of oil fields currently being exploited have reached maturity and have therefore begun to decline in production or are about to do so. The recovery rate (yield) of these fields is currently around 15 to 35% on average, in relation to the initial amount of hydrocarbons (petroleum and / or gas). They therefore offer a production potential which is still considerable.

[0007] Generally, the hydrocarbons, for example crude petroleum, contained in these deposits is recovered in several stages.

[0008] The production results first of all from the natural energy of the fluids and the rock which become decompressed. At the end of this depletion phase, the amount of hydrocarbons recovered at the surface represents on average around 5 to 15% of the initial reserve. It is therefore necessary, in a second stage, to use techniques which aim to increase the recovery yield by maintaining the pressure in the field.

[0009] The most frequently implemented method consists in injecting water into the deposit through injection wells intended for this purpose. This is referred to as secondary recovery. This second phase ends when the water / hydrocarbons ratio is too high, i.e. when the amount of water in the mixture produced by the production wells is too high. This secondary recovery thus makes it possible to obtain an additional recovery rate of around 10 to 20%.

[0010] The other techniques that can be used are grouped together under the name “enhanced recovery of petroleum or hydrocarbons”, or “enhanced oil recovery” (EOR). Their aim is to recover between 10 and 35% of additional hydrocarbons relative to the initial amount of hydrocarbons. The term enhanced recovery of petroleum or hydrocarbons covers various thermal or non-thermal techniques, such as enhanced electric, miscible, steam or chemical recovery of remaining hydrocarbons (see “Oil & Gas Science and Technology” - Revue IFP, vol 63 (2008) no. 1, pages 9-19).

[0011] The term “petroleum” denotes any type of oil, namely light oil, heavy oil or even bituminous oil. An oil is usually the result of the natural transformation of organic matter and is composed of a mixture of hydrocarbons. In the description of the prior art or of the invention, the terms "petroleum" (or hydrocarbons) and "oil" are used to denote the same material, unless mentioning the composition of an emulsion or of a dispersion.

[0012] The efficiency of water injection flushing is generally improved by the addition of water- soluble polymers. The expected and proven benefits of the use of polymers, through the "viscosification" of the injected water, are the improvement in flushing and the reduction in the viscosity contrast between the fluids in order to control their mobility ratio in the field, in order to recover the hydrocarbons quickly and efficiently. The most commonly used polymers for increasing the viscosity of water are polymers based on acrylamide and / or acrylic acid and / or 2-acrylamido-2-methylpropanesulfonic acid (ATBS), and / or the salts thereof.

[0013] Polymers added to the injection water are generally subject to long residence times in the deposit, between the injection wells and the production wells, which can range from a few months to a few years. During this period of time, they may undergo thermal degradation linked to an increase in their degree of hydrolysis by conversion of acrylamide units into acrylates, or chemical degradation leading to chain breakage (decrease in molecular weight) by radical attack. In both cases, these mechanisms generally result in a decrease in viscosity and therefore a loss of the efficiency of flushing the subterranean formation with the injected aqueous polymer solution. There is therefore a real benefit to developing polymers that are more resistant to these processes encountered at enhanced hydrocarbon recovery sites (petroleum and / or gas).

[0014] EP 3 770 232 teaches an oil recovery method involving a composition comprising an inverse emulsion of an acrylamide polymer and solid particles of a polymer of acrylamide and ATBS.

[0015] CA 3 056 975 teaches an oil recovery method involving a polymer of ATBS. FR 2 986 034 teaches an oil recovery method involving a water-soluble polymer of ATBS and a monomer selected from acrylamide, N-Vinylpyrrolidone and acrylamide derivatives.

[0016] EP 3 816 228 teaches a hydraulic fracturing involving an inverse emulsion of polymer.

[0017] It is known to those skilled in the art that synthetic water-soluble polymers based on 2- acrylamido-2-methylpropanesulfonic acid (ATBS and / or the salts thereof) or a monomer functionalized with a sulfonic acid group (and / or the salts thereof) are tolerant to divalent salts and also to high temperatures. They are therefore advantageously used for high- salinity injection fluids, while polymers based on acrylamide and on acrylic acid can be used for low-salinity water.

[0018] The use of low-salt solutions for the preparation of water-soluble polymer injection solutions intended for flushing operations is generally favoured in the early phases of projects in order to demonstrate the efficiency of the polymer on a pilot scale. The use of production water, which is generally saltier, is then favoured during expansion phases in order to minimise stress on freshwater resources. However, in some cases the opposite situation may arise. Examples are given below:

[0019] * The water produced is very often reinjected. However, when this water is very salty (100 to 280 g / 1 TDS approximately) and particularly rich in divalent cations, and the temperature of the reservoir is around 80°C to 140°C, the use of polymers having very high contents of sulfonated acrylamide (ATBS) is required. This type of polymer has a significant cost for the project, since the unit cost thereof is generally 20% to 100% higher than that of polymers such as acrylamide and acrylic acid copolymers. The dosage thereof also has to be higher, by 15% to 50% (by weight). In these specific cases, the use of softer water, regardless of the origin (aquifer, softening process), enabling the use of less expensive polymers (unit cost and / or lower dosage) may be favoured in view of the overall cost of the project. This may particularly be the case in some countries in the Middle East, where large amounts of seawater are softened for supplying water to the population and for irrigation.

[0020] * In the case of flushing operations requiring the use of alkalis (AP: alkaline-polymer; ASP: alkaline-surfactant-polymer), it is necessary to soften the injection water to prevent the formation of mineral deposits in the presence of alkalis. It is then common to begin with a first phase of injecting polymer solution into salt water before moving on to injecting the AP or ASP slug into softened water. However, in carbonate reservoirs, and when the injection fluid containing the water-soluble polymer is prepared from a low-salt solution, calcium ions from the rock enrich the fluid with divalent cations during the flushing operation. Depending on the degree of hydrolysis of the polymer, or in the absence of a sufficient amount of ATBS in the polymer, this phenomenon of calcium ion enrichment can lead to the precipitation of the polymer in the reservoir.

[0021] In this case, the use of polymers based on a monomer of the ATBS type could be favoured, but these monomers are much more expensive than monomers such as acrylamide or acrylic acid and, for a complete flushing campaign of a subterranean formation where hundreds of tons of polymers can be used, the financial impact is considerable.

[0022] Disclosure of the invention

[0023] The Applicant has found and developed a method for the enhanced recovery of hydrocarbons (petroleum and / or gas) using a sequential injection of different fluids having distinct compositions (nature of the polymer and optionally salinity of the solution) making it possible to prevent the degradation of the injected polymers (makes it possible to reduce the risks of incompatibility or precipitation during the injection of an alkaline solution into the reservoir), to optimise the costs of hydrocarbon recovery and to optimise the water resources and therefore to reduce the environmental impact of the enhanced recovery operation.

[0024] More specifically, the invention relates to a method for the enhanced recovery of hydrocarbons (petroleum and / or gas) in a subterranean formation comprising one or more injection wells and one or more production wells, the method comprising at least the following steps: a) preparing an aqueous injection fluid SI by dissolving a polymer Pl in salt water Al having a total salinity [TDSJi and a concentration of divalent cations [Div+]i, the polymer Pl comprising:

[0025] - xi mol% of nonionic hydrophilic monomer, with 0 < xi < 85,

[0026] - yi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with 0 < yi < 85, and

[0027] - zi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with 15 < zi < 100; with xi + yi + zi = 100 b) injecting the aqueous injection fluid SI into one or more injection wells Pu of a subterranean formation and flushing the subterranean formation using this aqueous injection fluid SI; c) preparing an aqueous injection fluid S2 by dissolving a polymer P2 in salt water A2 having a total salinity [TDSJi and a concentration of divalent cations [Div+Ji, with [TDSJi < [TDSJi and [Div+]2< [Div+]i / 2, the polymer P2 containing:

[0028] - 2 mol% of nonionic hydrophilic monomer, with 50 < i < 92.5,

[0029] - y2mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with 0 < y2< 50, and

[0030] - zi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with z2< zi / 2; with 2 + yi + zi = 100 d) stopping the injection of the aqueous injection fluid SI; e) injecting the aqueous injection fluid S2 into the well(s) Pu and flushing the subterranean formation using this aqueous injection fluid S2; f) recovering an aqueous mixture and hydrocarbons from one or more production wells in the subterranean formation.

[0031] In this method, polymer Pl comprises more anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function than polymer P2, z2< zi / 2.

[0032] The injection of the aqueous injection fluid SI is stopped when the subterranean formation has a stabilised resistance factor. The resistance factor corresponds to the force opposing the flow of the fluid in the subterranean formation. In general, this stabilisation is advantageously obtained after the injection of an amount of aqueous injection fluid SI of between 0.05 and 0.75 times the pore volume of the subterranean formation, more advantageously between 0.1 and 0.4.

[0033] The injection of the first fluid SI and the resulting flushing of the subterranean formation makes it possible to subsequently improve (step e)) the efficiency of the flushing of this subterranean formation by the second fluid S2. The injection of S2, after the formation of an Al / Pl contact front on the rock, resistant to reservoir conditions (and expensive) makes it possible to serve as a buffer to allow the injection of a front (A2 / P2, less expensive) that may have compatibility problems with reservoir conditions (temperature / salinity) while being fully compatible with the Al / Pl front. Without being bound to a particular theory, the injection of the first fluid SI appears to make it possible to cover the surface of the rocks of the subterranean formation with a layer of polymer (Pl) while improving the control of the mobility of the injected water.

[0034] The front corresponds to the transition or contact zone between two fluids injected in succession into the subterranean formation. This is the region where a first fluid (in this case Al / Pl) comes into contact with the rock of the reservoir and prepares the way for the injection of a second fluid (in this case A2 / P2). This front plays a key role in the efficient flushing of the reservoir by forming an interface that regulates the chemical and thermal compatibility of the injected fluids while ensuring control of the mobility of the subsequent injection.

[0035] In the case of carbonate formations, it would seem that this layer of polymer formed at the surface of the rock (following injection of the fluid SI) limits, and in some cases prevents, the release of calcium ions by the rock during its subsequent exposure to less salty water (second fluid S2). The polymer P2 would thus be less exposed to divalent ions (risk of precipitation of the polymer) because the latter would not, or only to a limited extent, be released into the fluid S2.

[0036] In the case of sandstone formations, injection of the fluid SI appears to have an additional advantage. Polymers containing sulfonated monomers generally have lower adsorption onto the rock than polymers without sulfonated monomers. The polymer Pl appears to act as a sacrificial agent from the perspective of adsorption, making it possible to reduce or even prevent the adsorption of the polymer P2 injected in the fluid S2.

[0037] The amount of aqueous injection fluid S2 injected during step e) is advantageously between 0.05 and 0.85 times the pore volume of the subterranean formation, more advantageously between 0.15 and 0.55.

[0038] The invention covers all possible combinations of the various embodiments disclosed, whether they are preferred embodiments or are given by way of example. Furthermore, when ranges of values are indicated, the limit values are included in these ranges. The disclosure also includes all of the combinations between the limit values of these ranges of values. For example, the ranges of values “1-20, preferentially 5-15” imply disclosure of the ranges “1-5”, “1-15”, “5-20” and “15-20” and the values 1, 5, 15 and 20.

[0039] The term “polymer” denotes a homopolymer prepared from a monomer, or a copolymer prepared from at least two different monomers.

[0040] Preferentially, the polymers Pl, P2 used in the method of the invention have (independently of one another) a molecular weight of greater than 0.5 million daltons, more preferentially between 1 and 40 million daltons, even more preferentially between 1 and 30 million daltons, even more preferentially between 2 and 20 million daltons, and even more preferentially between 3 and 15 million daltons. The molecular weight is the weight-average molecular weight.

[0041] The molecular weight is determined by the intrinsic viscosity of the polymer. The intrinsic viscosity can be measured by methods known to those skilled in the art and can be calculated from the reduced viscosity values for different polymer concentrations by a graphical method consisting in plotting the reduced viscosity values (y-axis) against the concentration (x-axis) and extrapolating the curve down to a concentration of zero. The intrinsic viscosity value is plotted on the y-axis or using the least-squares method. The molecular weight can then be determined using the Mark-Houwink equation:

[0042] [q] = K M" where [q] represents the intrinsic viscosity of the polymer as determined by the solution viscosity measurement method.

[0043] K represents an empirical constant.

[0044] M represents the molecular weight of the polymer, a represents the Mark-Houwink coefficient.

[0045] K and a depend on the particular polymer-solvent system.

[0046] The term "water-soluble polymer” denotes a polymer that gives an aqueous solution without insoluble particles when it is dissolved with stirring at 25°C and at a concentration of 10 g.l1in deionised water.

[0047] The term “hydrophilic monomer” denotes a monomer that has an octanol-water partition coefficient, Kow, of less than or equal to 1, in which the partition coefficient Kowis determined at 25°C in an octanol-water mixture having a volume ratio of 1 / 1, at a pH of between 6 and 8. The term “hydrophobic monomer” denotes a monomer that has an octanol-water partition coefficient, Kow, of greater than 1, in which the partition coefficient Kowis determined at 25°C in an octanol-water mixture having a volume ratio of 1 / 1, at a pH of between 6 and 8.

[0048] For polymers Pl (when xi 0 ) and P2, independently of one another:

[0049] - the nonionic hydrophilic monomers are selected from the group comprising water-soluble vinylic monomers, preferentially from the group consisting of: acrylamide, methacrylamide, N-alkyl acrylamides, N-alkyl methacrylamides, N,N-dialkyl acrylamides (for example N,N-dimethylacrylamide or N,N-diethylacrylamide), N,N-dialkyl methacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol (meth)acrylamide, N-vinylcaprolactam, N- vinylformamide (NVF), N-vinylacetamide, N-vinylimidazole, N-vinylsuccinimide, acryloyl morpholine (ACMO), glycidyl methacrylate, glyceryl methacrylate, diacetone acrylamide, methacrylic anhydride, acrylonitrile, maleic anhydride, itaconic anhydride, itaconamide, vinylpyridine, hydroxyalkyl (meth)acrylates, thioalkyl (meth)acrylates, isoprenol, alkoxylated derivatives of isoprenol, hydroxyethyl (meth)acrylates, alkoxylated derivatives of hydroxy ethyl (meth)acrylates, hydroxypropyl acrylate, alkoxylated derivatives of hydroxypropyl acrylate, vinyl acetate, and mixtures thereof, the alkyl groups being C1-C3 hydrocarbon chains; preferably acrylamide;

[0050] - the anionic hydrophilic monomers comprising at least one partially or totally salified carboxylic acid function are selected from the group consisting of: acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, C1-C3 itaconic acid hemiesters, crotonic acid, maleic acid, fumaric acid, and mixtures thereof; preferably acrylic acid and / or a salt thereof;

[0051] - for Pl, and for P2 when Z2 0, the anionic hydrophilic monomers comprising at least one partially or totally salified sulfonic acid function are selected from the group consisting of: allylsulfonic acid, methallylsulfonic acid, 2-methylidenepropane-l,3-disulfonic acid, styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (ATBS), 2-acrylamido- 2-methylpropanedisulfonic acid, 3-allyloxy-2-hydroxypropanesulfonic acid, and mixtures thereof; preferably ATBS and / or a salt thereof.

[0052] The water-soluble salts of the anionic hydrophilic monomers are advantageously alkali metal salts (preferentially sodium or potassium) or alkaline-earth metal salts (preferentially calcium or magnesium) or ammonium salts (preferentially NH4+). Advantageously, for polymers Pl and P2 (independently of one another):

[0053] - for Pl when xi 0, and for P2, the nonionic hydrophilic monomer is acrylamide,

[0054] - when yi 0 and / or yi 0, the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function is acrylic acid,

[0055] - for Pl and for P2, the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function is 2-acrylamido-2-methylpropanesulfonic acid.

[0056] Even more advantageously, for polymers Pl and P2 (independently of one another):

[0057] - for Pl when xi 0, and for P2, the nonionic hydrophilic monomer is acrylamide,

[0058] - when yi 0 and / or yi 0, the anionic hydrophilic monomer comprising at least one totally salified carboxylic acid function is sodium acrylate,

[0059] - for Pl and for P2 when Z2 0, the anionic hydrophilic monomer comprising at least one totally salified sulfonic acid function is sodium 2-acrylamido-2-methylpropanesulfonate.

[0060] According to a preferred embodiment, the aqueous injection fluid SI contains between 0.1% and 2% by weight (relative to the weight of the aqueous fluid SI) of polymer Pl and the aqueous injection fluid S2 contains between 0.1% and 2% by weight (relative to the weight of the aqueous fluid S2) of polymer P2.

[0061] Advantageously, polymer Pl is a polymer of ATBS (partially or totally salified) and acrylamide.

[0062] Advantageously, polymer P2 is a polymer of ATBS (partially or totally salified), acrylamide and acrylic acid (partially or totally salified).

[0063] Advantageously, the method of the invention comprises, between steps d) and e):

[0064] - injecting an aqueous injection fluid Sint into the injection well(s) Pu, and

[0065] - flushing the subterranean formation using this fluid Sint, said injection fluid Sint comprising a water-soluble polymer Pint dissolved in salt water Aint having a total salinity [TDSJint and a concentration of divalent cations [Div+]int, with [TDS]2 < [TDSJint < [TDSJi and [Div+]2< [Div+]i„t < [Div+]i, the water-soluble polymer Pint comprising:

[0066] - xint mol% of nonionic hydrophilic monomer, with 0 < xint < 92.5,

[0067] - yint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function with 0 < yint < 92.5, and

[0068] - zint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with Z2<zint<zi and xint + yint + zint= 100.

[0069] The injection of the fluid Sint into the well(s) Pu is stopped before the injection of the aqueous injection fluid S2.

[0070] For the water-soluble polymer Pint:

[0071] - the nonionic hydrophilic monomer is selected from the group consisting of acrylamide, methacrylamide, N-alkyl acrylamides, N-alkyl methacrylamides, N,N-dialkyl acrylamides, N,N-dialkyl methacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol (meth)acrylamide, N-vinylcaprolactam, N-vinylformamide (NVF), N-vinylacetamide, N-vinylimidazole, N-vinylsuccinimide, acryloyl morpholine (ACMO), glycidyl methacrylate, glyceryl methacrylate, diacetone acrylamide, methacrylic anhydride, acrylonitrile, maleic anhydride, itaconic anhydride, itaconamide, vinylpyridine, hydroxyalkyl (meth)acrylates, thioalkyl (meth)acrylates, isoprenol, alkoxylated derivatives of isoprenol, hydroxyethyl (meth)acrylates, alkoxylated derivatives of hydroxyethyl (meth)acrylates, hydroxypropyl acrylate, alkoxylated derivatives of hydroxypropyl acrylate, vinyl acetate, and mixtures thereof, the alkyl groups being C1-C3 hydrocarbon chains; preferably acrylamide;

[0072] - the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function is selected from the group consisting of acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, C1-C3 itaconic acid hemiesters, crotonic acid, maleic acid, fumaric acid, and mixtures thereof; preferably acrylic acid;

[0073] - the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function is selected from the group consisting of allylsulfonic acid, methallylsulfonic acid, 2-methylidenepropane-l,3-disulfonic acid, styrenesulfonic acid, 2- acrylamido-2-methylpropanesulfonic acid (ATBS), 2-acrylamido-2- methylpropanedisulfonic acid, 3-allyloxy-2-hydroxypropanesulfonic acid, and mixtures thereof; preferably ATBS.

[0074] The amount of aqueous injection fluid Sint injected between steps d) and e) is advantageously between 0 and 0.5 times the pore volume of the subterranean formation, more advantageously between 0.05 and 0.3.

[0075] The polymer Pint preferentially has a molecular weight of at least 0.5 million daltons, more preferentially between 1 and 40 million daltons, even more preferentially between 1 and 30 million daltons, even more preferentially between 2 and 20 million daltons, and even more preferentially between 3 and 15 million daltons. The molecular weight is the weight-average molecular weight and is measured as indicated above for polymers Pl and P2.

[0076] Polymers Pl, P2 and Pint advantageously have (independently of one another) a degree of salification of the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function of between 30% and 100%, relative to the number of carboxylic acid functions.

[0077] Polymers Pl, P2 and Pint advantageously have (independently of one another) a degree of salification of the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function of between 30% and 100%, relative to the number of sulfonic acid functions.

[0078] The monomers of the polymer Pint are preferentially selected from the same lists as those of the polymers Pl and P2. The preferential monomers of Pl and P2 are advantageously those of Pint.

[0079] Preferentially, the fluid Sint contains between 0.1% and 2% by weight (relative to the weight of the fluid Sint) of polymer Pint.

[0080] Optionally, polymers Pl, P2 and Pint may contain less than 1 mol% of cationic hydrophilic monomers and / or of zwitterionic hydrophilic monomers and / or of hydrophobic monomers.

[0081] The polymers used in the method of the invention (Pl, P2 and optionally Pint) may have (independently of one another) a linear, branched, star-shaped or comb-shaped structure. This structure can be obtained, according to the general knowledge of those skilled in the art, for example by selecting the initiator; the transfer agent; the concentration; or the polymerisation technique, such as Reversible Addition Fragmentation chain Transfer Polymerization (RAFT), Nitroxide Mediated Polymerization (NMP) or Atom Transfer Radical Polymerization (ATRP), for the incorporation of structural monomers.

[0082] The polymers may further by structured by a branching agent. The term “structured polymer” denotes a non-linear polymer that has side chains.

[0083] The branching agent is advantageously selected from:

[0084] - structuring agents, which may be selected from the group consisting of polyethylenically unsaturated compounds (having at least two unsaturated functions), for instance vinyl functions, particularly allyl or acrylic functions, and mention may for example be made of methylenebisacrylamide (MBA), triallyamine, tetraallylammonium chloride or 1,2- dihydroxyethylenebis(N-acrylamide),

[0085] - compounds having at least two epoxy functions,

[0086] - compounds having at least one unsaturated function and one epoxy function,

[0087] - macro-initiators such as polyperoxides, polyazos and poly-transfer agents such as polymercaptan polymers and polyols,

[0088] - functionalised polysaccharides,

[0089] - water-soluble metal complexes composed of:

[0090] * a metal having a valency of greater than 3 such as, by way of non-limiting example, aluminium, boron, zirconium or titanium, and

[0091] * a ligand bearing a hydroxyl function.

[0092] The amount of branching agent in the polymers is advantageously less than 1000 ppm by weight relative to the total weight of the monomers of the polymer, preferentially less than 100 ppm by weight, more preferentially less than 10 ppm by weight. When a branching agent is used, the amount thereof is advantageously at least 1 ppm.

[0093] Water-soluble polymers comprising at least one branching agent remain water-soluble. Those skilled in the art know how to adjust the amount of branching agent and optionally the amount of transfer agent in order to achieve this result.

[0094] In a particular embodiment, polymers Pl, P2 and Pint do not comprise a branching agent.

[0095] Polymer Pl comprises xi mol% of nonionic hydrophilic monomer, with xi between 0 and 85 and more preferentially between 10 and 80.

[0096] Polymer P2 comprises X2 mol% of nonionic hydrophilic monomer, with X2 between 50 and 92.5, preferentially between 55 and 85%, and even more preferentially between 60% and 85%.

[0097] Polymer Pint comprises xint mol% of nonionic hydrophilic monomer, with xint between 0 and 92.5, preferentially between 5 and 92.5, and even more preferentially between 10 and 90.

[0098] Polymer Pl comprises yi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with yi between 0 and 85, preferentially between 10 and 25, and even more preferentially between 10 and 15.

[0099] Polymer P2 comprises yi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with yi between 0 and 50, preferentially between 15 and 50, and even more preferentially between 20 and 50.

[0100] Polymer Pint comprises yint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with yint between 0 and 92.5, preferentially between 0 and 70, and even more preferentially between 0 and 50.

[0101] Polymer Pl comprises zi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with zi between 15 and 100, advantageously between 10 and 90, preferentially between 15 and 90, and even more preferentially between 20 and 90.

[0102] Polymer P2 comprises Z2 mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with Z2 less than 50%, more preferentially less than 30%.

[0103] Pl is preferably a polymer of acrylamide and sodium 2-acrylamido-2- methylpropanesulfonate.

[0104] P2 is preferably a polymer of acrylamide and sodium 2-acrylamido-2- methylpropanesulfonate or a polymer of a polymer of acrylamide and sodium acrylate.

[0105] Polymer Pint comprises zint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with Z2<zint<zi.

[0106] Polymers Pl, P2 and Pint used to prepare solutions SI, S2 and Sint can be (independently of one another) in liquid form or in solid form. Thus, prior to the formation of the aqueous injection fluid, each polymer can be in the form of an inverse emulsion (water in oil), an aqueous suspension, a powder or a dispersion of the polymer in oil. The polymers are preferably in the form of powders or inverse emulsion.

[0107] In the formation of the aqueous injection fluids SI, S2 and Sint, dissolving the polymer in salt water includes mixing the polymer (in any form) and the salt water, for example mixing the polymer in the form of an inverse emulsion and the salt water, or mixing the polymer in the form of a powder and the salt water.

[0108] When the polymers are in solid (advantageously powder) form, they can be partially or totally dissolved in aqueous solution in order to obtain fluids SI, S2 or Sint by means of a polymer preparation unit such as the Polymer Slicing Unit (PSU) disclosed in EP 2 203 245.

[0109] The injection fluids (SI, S2 and Sint) contain the polymers (Pl, P2 and Pint) and, depending on the technique used, one or more chemical compounds that can be used for enhanced hydrocarbon recovery. Among these chemical compounds, mention will be made of the use of weak, strong or super-strong mineral or organic bases that can saponify crude hydrocarbons and form surface-active species in-situ that solubilise hydrocarbons. Examples thereof include sodium carbonate, caustic soda NaOH, borate compounds, metaborate compounds, amines, basic polymeric species, and mixtures thereof. Another family of compounds commonly injected with polymers is that of surfactant compounds, which are often anionic, zwitterionic, cationic and sometimes also nonionic. These compounds are rarely injected in pure form, rather with a co-surfactant and a co-solvent to improve their compatibility and effectiveness in the reservoir.

[0110] Salt waters Al, A2 and Aint are prepared (independently of one another) from monovalent and / or polyvalent salts or combinations thereof. Examples of salts include, but are not limited to, sodium salts, lithium salts, potassium salts, magnesium salts, aluminium salts, ammonium salts, phosphate salts, sulfate salts, chloride salts, fluoride salts, citrate salts, acetate salts, tartrate salts, hydrogen phosphate salts, water-soluble inorganic salts, other inorganic salts and mixtures thereof.

[0111] Salt waters Al, A2 and Aint preferably contain (independently of one another) at least one of the following components: sodium chloride, calcium chloride, sodium bromide, calcium bromide, zinc bromide, sodium formate and potassium formate.

[0112] Preferably, the total salinity [TDSJi of the saline solution Al (concentration by weight) is between 1,000 ppm and 330,000 ppm.

[0113] Preferably, the total salinity [TDSJi of the saline solution A2 (concentration by weight) is between 100 ppm and 50,000 ppm.

[0114] Preferably, the total salinity [TDSJint of the saline solution Aint (concentration by weight) is between 500 ppm and 150,000 ppm.

[0115] Preferably, the concentration of divalent cations [Div+]i (by weight) in salt water Al is between 100 ppm and 30,000 ppm.

[0116] Preferably, the concentration of divalent cations [Div+Ji (by weight) in salt water A2 is between 0 ppm and 6,000 ppm.

[0117] Preferably, the concentration of divalent cations [Div+]int (by weight) in salt water Aint is between 100 ppm and 20,000 ppm.

[0118] The invention and its resulting advantages will be better understood in the light of the following figures and examples, which are provided as a non-limiting illustration of the invention.

[0119] Figures

[0120] Figure 1 shows the variation in the resistance factor of a core sample from a subterranean formation as a function of the injected amount of polymer expressed as pore volume equivalents of the core sample.

[0121] Figure 2 shows the turbidity of a polymer solution in desalinated seawater aged for 7 days at 120°C as a function of the calcium concentration.

[0122] Figure 3 shows the change in the residual viscosity of solutions of the polymers during the ageing thereof at 80°C under anaerobic conditions.

[0123] Figure 4 shows the variation in the resistance factor of a sandstone rock as a function of the injected amount of polymer expressed as pore volume equivalents of the sandstone rock.

[0124] Examples

[0125] Example no, 1 : Case of a carbonate reservoir at high temperature and high salinity

[0126] The tests below were carried out in core samples of carbonate reservoir rock originating from the Middle East, the permeability of which is around 150 md. Each core sample is saturated with a formation water having a total salinity of 236 g / 1 and a concentration of divalent cations of 16.5 g / 1 (see the composition in Table 2) at a temperature of 120°C. The two scenarios described in Table 1 were compared. Polymer Pl-1 is a polymer of sodium ATBS (70 mol%, totally salified ATBS) and of acrylamide (30 mol%).

[0127] Polymer Pint is identical to polymer Pl-1.

[0128] Polymer P2-1 is a polymer of sodium ATBS (25 mol%, totally salified ATBS) and of acrylamide (75 mol%), thus having an anionicity of 25 mol%.

[0129] Table 1 : Scenarios of injection into the carbonate reservoir rock.

[0130] Table 2: Composition of the salt waters Al, Aint and A2 of Example 1.

[0131] The results obtained according to scenarios #1 and #2 are illustrated by Figure.

[0132] Al and P-1-1 form the fluid SI. Aint and Pint form the fluid Sint. A2 and P2-1 form the fluid S2-1.

[0133] * Summary of scenario #1 :

[0134] - Sequence #1 (See. #1 - Seq. #1 : SI = 14.5 pore volumes):

[0135] The injection of polymer Pl-1 at 2,000 ppm (by weight) into the production water, performed in a core sample at 120°C, leads to rapid stabilisation of the resistance factor at a value of approximately 10 ± 0.2 after the injection of an amount of fluid (SI) equivalent to a little less than 2.5 times the pore volume of the core sample. This indicates excellent injectivity / propagation of the polymer in the porous medium.

[0136] - Sequence #2 (See. #1 - Seq. #2: Sint = 7 pore volumes):

[0137] After injecting an amount of fluid (SI) equivalent to 14.5 times the pore volume of the core sample, the transition to injecting (Sint) the polymer Pint at 1,500 ppm (concentration adjusted to keep the same injected viscosity) in seawater containing 42 g / 1 TDS (Aint) leads to a slight increase in the resistance factor from a value of approximately 10 to a value of around 11.2. Despite maintaining the same injected viscosity, it is suspected that the change in salinity leads to swelling of the adsorbed polymer layer formed during sequence #1 at higher salinity, which leads to this increase in the resistance factor. This transition occurs after the injection of an amount of fluid (Sint) equivalent to approximately less than 2 times the pore volume of the core sample, and the resistance factor then remains stable during the injection of an additional amount of fluid (Sint) equivalent to 5 times the pore volume of the core sample. Once again, this behaviour illustrates the good injectivity of the polymer solution under these conditions.

[0138] - Sequence #3 (See. #1 - Seq. #3: S2= 11 pore volumes):

[0139] After 21.5 pore volumes (SI + Sint), the transition to injecting the polymer P2-1 at 800 ppm into the desalinated seawater containing 241 ppm TDS (S2) leads to a more significant increase in the resistance factor, which goes from a value of 11.2 to approximately 18. Again, the polymer concentration was adjusted so as to maintain the same injected viscosity value. Similarly, the increase in the resistance factor is attributed to swelling of the adsorbed polymer layer under the effect of the decrease in salinity. The contrast in salinity between sequence #2 and sequence #3 being much more significant than between sequences #1 and #2 explains the greater increase in the resistance factor due to swelling of the adsorbed polymer layer. The resistance factor then remains stable during the injection of an additional amount of fluid (S2) equivalent to 10 times the pore volume of the core sample, indicating that the polymer solution exhibits no injectivity problems under these conditions.

[0140] * Summary of scenario #2 (See. #2: S2= 13 pore volumes):

[0141] Polymer P2-1 used during sequence #3 of scenario #1 was this time directly injected (S2) at 800 ppm into the desalinated seawater containing 241 ppm TDS in the core sample. An increase in the resistance factor is initially observed after the injection of an amount of fluid (S2) equivalent to 5 times the pore volume of the core sample, before tending towards a value of approximately 10, corresponding to the relative viscosity of the injected fluid (S2). However, after the injection of an additional amount of fluid (S2) equivalent to 1 to 2 times the pore volume of the core sample, the value of the resistance factor increases linearly with the amount of fluid (S2) injected and expressed as pore volume equivalents of the core sample. This behaviour is attributed:

[0142] * firstly, to a rapid increase in the degree of hydrolysis of the polymer under the effect of temperature, with conversion of the acrylamide units into sodium acrylate, and

[0143] * secondly, to a release of calcium by the carbonate rock exposed to the desalinated seawater A2 of very low salinity.

[0144] Figure 1 illustrates the injection profiles during the injection of the different sequences corresponding to scenarios #1 (Sl+Sint+S2) and #2 (S2) described in Table 1.

[0145] To illustrate the latter point (release of calcium by carbonate rock), core samples were subjected to injections of fluids of different salinities:

[0146] * virgin reservoir rock exposed to the injection of formation water containing 236 g / 1 TDS

[0147] * reservoir rock containing pre-adsorbed polymer Pl-1 (injection of polymer Pl-1 carried out in the formation water according to scenario #1 sequence #1; SI) exposed to the injection of desalinated seawater containing 241 ppm TDS (A2)

[0148] * virgin reservoir rock exposed to the injection of desalinated seawater containing 241 ppm TDS (A2).

[0149] The contents of calcium ions released into the effluents during each sequence were determined by ICP-MS and are given in Table 3.

[0150] Table 3 : Tests of the release of calcium by the reservoir rock depending on the fluid injected. It was not possible to detect the slightest release of calcium by the reservoir rock when it was exposed to the flow of formation water (Al). Similarly, when the rock was covered beforehand with polymer Pl-1 (SI), its subsequent exposure to highly desalinated water, in this case desalinated seawater containing 241 ppm TDS (A2), it was not possible to detect the presence of calcium released by the rock in the effluents. In contrast, in the case of a sample of virgin rock, the rate of calcium release upon exposure to a flow of desalinated seawater (A2) was measured as being around 700 ppm. In this case, the presence of a layer of pre-adsorbed polymer Pl-1 very strongly limits, if not entirely inhibits, the release of calcium in solution.

[0151] Additionally, polymer P2-1 was subjected to 7 days of ageing at 120°C in desalinated seawater (A2), then metered additions of calcium were carried out while monitoring the change in the turbidity of the polymer solution depending on the content of calcium added. According to the results given in Figure 2, the turbidity begins to increase sharply from 175 ppm of released calcium, indicating a compatibility problem between the polymer and the calcium present in solution.

[0152] Figure 2 illustrates the calcium tolerance of a solution of polymer P2-1 prepared at 750 ppm by weight in desalinated seawater (A2) and aged for 7 days at 120°C.

[0153] These tests demonstrate the advantage of performing sequential injection. The first step consists in injecting a polymer which is resistant to harsh conditions; in this case, a carbonate rock saturated with a formation water of very high salinity (A2, 236 g / 1) and at very high temperature (120°C). This first injection makes it possible to form a protective film that prevents the release of calcium by the reservoir rock during its subsequent exposure to water of very low salinity. This protective film thus enables, in a second step, the injection of a less robust, and therefore more economical, polymer at a significantly lower concentration. This sequence makes it possible to ensure good injectivity and good transport of the polymer solutions into the porous medium. It is also possible to add an intermediate step consisting of the injection of an intermediate polymer Pint, between Pl-1 and P2-1, into a water of intermediate salinity in order to reduce the risk of incompatibility during an excessively sudden change in the salinity of the injection water.

[0154] In contrast, the direct injection of polymer P2-1 into the water of low salinity quickly leads to irreversible damage to the porous medium due to the incompatibility between polymer P2-1, which hydrolyses while it resides in the porous medium at 120°C, and the release of calcium by the reservoir rock exposed to water of low salinity, which leads to the precipitation of the polymer.

[0155] Example no. 2: Case of a sandstone reservoir at a relatively high temperature in the presence of divalent cations

[0156] In the case of a sandstone reservoir having a permeability of around 1,200 md, a water salinity of 50 g / 1 TDS and a temperature of around 80°C, the most suitable polymer is polymer P2-1 (75 mol% of acrylamide (AM) and 25 mol% of ATBS sodium) (SPAM), since copolymer P2-2 (70 mol% of acrylamide and 30 mol% of sodium acrylate (AA)) (HP AM) does not offer the required stability under these conditions, as shown in Figure 3.

[0157] On the other hand, in the case of the use of water containing 30 g / 1 TDS as injection water, HP AMs offer very good thermal stability over a minimum period of one year, and their use makes more sense from an economic perspective due to a lower unit price than an ATBS- based polymer but also a lower dosage to reach the same viscosity value due to the decrease in salinity.

[0158] Table 4: Composition of the salt waters Al, Aint and A2 of Example 2.

[0159] Table 5: Composition of the polymers used in example 2.

[0160] Figure 3 illustrates the change in residual viscosity of solutions of polymers P2-1 and P2-2, prepared at the same viscosity in production water (Al, 50 g / 1) and in seawater (30 g / 1) over time, during the ageing thereof at 80°C under anaerobic conditions.

[0161] Figure 4 gives the sequential injections of polymer P2-1 prepared in 50 g / 1 TDS brine, then of polymer P2-2 prepared in 30 g / 1 TDS brine, at the same viscosity in a core sample of sandstone rock of the reservoir, having a permeability of around 1200 md. These injections, carried out at an injection speed of 61 cm / day, indicate very good injectivity and propagation of the polymer solutions.

[0162] The dynamic adsorption values of these two polymer solutions were determined by the two- front method, in which two fronts of the same polymer solution are injected into an initially virgin and brine-saturated rock core sample. The first polymer front is delayed by the adsorption of the polymer. When the polymer concentration at the core sample exit is identical to the injected concentration, the adsorption of the polymer onto the rock has been satisfied. A brine front is then inj ected (amount equivalent to 50 to 100 times the pore volume of the core sample) in order to remove any non-adsorbed polymer from the core sample. A second polymer front is then injected; this second front is no longer delayed since the adsorption has already been satisfied. The difference between the two fronts then makes it possible to determine the amount of polymer adsorbed on the rock.

[0163] We also proceeded in the same way in the case of the injection of a first front of the polymer P2-1 in 50 g / 1 TDS brine, followed by a second front but of the polymer P2-2 in 30 g / 1 TDS brine. The results obtained are given in Table 6.

[0164] Table 6: Adsorption values measured by the two-front method in the case of the injection of polymer P2-1 prepared in 50 g / 1 TDS brine, the injection of polymer P2-2 prepared in 30 g / 1 TDS brine, and during the injection of polymer P2-2 prepared in 30 g / 1 TDS brine and injected subsequently to an injection of polymer P2-1 prepared in 50 g / 1 TDS brine.

[0165] In the case of polymer P2-1 alone (#1), the adsorption value obtained is relative; it is measured as being equal to 25 pg of polymer per gram of rock. In the case of polymer P2-2 (#2) alone in 30 g / 1 TDS brine, the adsorption value obtained is much higher; it is measured as being equal to 139 pg / g of polymer per gram of rock. Finally, in the case of polymer P2- 2 injected in 30 g / 1 TDS brine after pre-injection of polymer P2-1 in 50 g / 1 brine (#3), no over-adsorption of polymer P2-2 is detected.

[0166] The strong adsorption of polymer P2-2 is explained by the relatively large amount of clay present in the reservoir rock, and by the composition of the polymer, since AM / AA copolymers are known to be particularly sensitive, from an adsorption perspective, to the presence of clay in sandstone rocks. On the other hand, the presence of ATBS in polymer P2-1 makes it possible to greatly minimise this impact and reduce adsorption in the presence of clay. This has already been reported in the literature, such as in this paper by Seright et al. (R.S. Seright, 2023). Interestingly, the pre-adsorption of polymer P2-1 makes it possible to prevent the adsorption of polymer P2-2 injected subsequently, exhibiting adsorption to a much lesser extent than polymer P2-2 injected directly.

[0167] These results confirm the benefit of injecting different polymers one after the other. The injection of a first polymer that is more robust and tolerant to high salinity, generally corresponding to the formation water or the produced water that is reinjected, makes it possible to envisage transitioning to a less robust but more economical polymer by injecting less salty water, which may be treated (desulfated) seawater or any other source of softer water (river, aquifer, water originating from another field or another formation), knowing that this polymer would not have been stable in the formation water or production water. This strategy also makes it possible to minimise the adsorption of the polymer, in particular in the presence of clay rocks. This type of transition is found in particularly in the alkaline- polymer or alkaline-surfactant-polymer methods in which it is necessary to use softened water which is less salty than the injection water used previously.

Claims

CLAIMS1. Method for the enhanced recovery of hydrocarbons in a subterranean formation comprising one or more injection wells and one or more production wells, the method comprising at least the following steps: a) preparing an aqueous injection fluid SI by dissolving a polymer Pl in salt water Al having a total salinity [TDSJi and a concentration of divalent cations [Div+]i, the polymer Pl comprising:- xi mol% of nonionic hydrophilic monomer, with 0 < xi < 85,- yi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with 0 < yi < 85, and- zi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with 15 < zi < 100; with xi + yi + zi = 100 b) injecting the aqueous injection fluid SI into one or more injection wells Pu of a subterranean formation and flushing the subterranean formation using this aqueous injection fluid SI; c) preparing an aqueous injection fluid S2 by dissolving a polymer P2 in salt water A2 having a total salinity [TDSJi and a concentration of divalent cations [Div+Ji, with [TDSJi< [TDSJi and [Div+]2< [Div+]i / 2, the polymer P2 containing:- xi mol% of nonionic hydrophilic monomer, with 50 < xi < 92.5,- y2mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function, with 0 < y2< 50, and- zi mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function, with z2< zi / 2; with xi + yi + zi = 100 d) stopping the injection of the aqueous injection fluid SI; e) injecting the aqueous injection fluid S2 into the well(s) Pu and flushing the subterranean formation using this aqueous injection fluid S2; f) recovering an aqueous mixture and hydrocarbons from one or more production wells in the subterranean formation wherein for the polymers Pl and P2, independently from each other:- the nonionic hydrophilic monomer is selected from the group consisting of: acrylamide,methacrylamide, N-alkyl acrylamides, N-alkyl methacrylamides, N,N-dialkyl acrylamides, N,N-dialkyl methacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol (meth)acrylamide, N-vinylcaprolactam, N-vinylformamide (NVF), N-vinylacetamide, N-vinylimidazole, N-vinylsuccinimide, acryloyl morpholine (ACMO), glycidyl methacrylate, glyceryl methacrylate, diacetone acrylamide, methacrylic anhydride, acrylonitrile, maleic anhydride, itaconic anhydride, itaconamide, vinylpyridine, hydroxyalkyl (meth)acrylates, thioalkyl (meth)acrylates, isoprenol, alkoxylated derivatives of isoprenol, hydroxyethyl (meth)acrylates, alkoxylated derivatives of hydroxy ethyl (meth)acrylates, hydroxypropyl acrylate, alkoxylated derivatives of hydroxypropyl acrylate, vinyl acetate, and mixtures thereof, the alkyl groups being C1-C3 hydrocarbon chains;- the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function is selected from the group consisting of: acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, C1-C3 itaconic acid hemiesters, crotonic acid, maleic acid, fumaric acid, and mixtures thereof;- the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function is selected from the group consisting of: allylsulfonic acid, methallylsulfonic acid, 2-methylidenepropane-l,3-disulfonic acid, styrenesulfonic acid, 2- acrylamido-2-methylpropanesulfonic acid (ATBS), 2-acrylamido-2- methylpropanedisulfonic acid, 3-allyloxy-2-hydroxypropanesulfonic acid, and mixtures thereof.

2. Method according to claim 1, characterised in that the polymers Pl and P2 have weight-average molecular weights of greater than 0.5 million daltons.

3. Method according to one of the preceding claims, characterised in that- for Pl when xi 0, and for P2, the nonionic hydrophilic monomer is acrylamide,- when yi 0 and / or yi 0, the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function is acrylic acid.

4. Method according to one of the preceding claims, characterised in that, for the polymers Pl and P2, the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function is 2-acrylamido-2-methylpropanesulfonic acid.

5. Method according to one of the preceding claims, characterised in that- for Pl when xi 0, and for P2, the nonionic hydrophilic monomer is acrylamide,- when yi 0 and / or yi 0, the anionic hydrophilic monomer comprising at least one totally salified carboxylic acid function is sodium acrylate.

6. Method according to one of the preceding claims, characterised in that- for Pl and for P2 when Z2 0, the anionic hydrophilic monomer comprising at least one totally salified sulfonic acid function is sodium 2-acrylamido-2-methylpropanesulfonate.

7. Method according to one of the preceding claims, characterised in that the aqueous injection fluid SI contains between 0.1% and 2% by weight of polymer Pl and in that the aqueous injection fluid S2 contains between 0.1% and 2% by weight of polymer P2.

8. Method according to one of the preceding claims, characterised in that the method comprises, between steps d) and e):- injecting an aqueous injection fluid Sint into the injection well(s) Pu and- flushing the subterranean formation using this fluid Sint, said aqueous injection fluid Sint comprising a water-soluble polymer Pint dissolved in salt water Aint having a total salinity [TDSJint and a concentration of divalent cations[Div+]int, with [TDS]i < [TDSJint < [TDSJi and [Div+]2 < [Div+]int < [Div+]i, the water-soluble polymer Pint comprising:- xint mol% of nonionic hydrophilic monomer, with 0 < xint < 92.5,- yint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function with 0 < yint < 92.5, and- zint mol% of anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function with Z2<zint<zi and xint + yint + zint= 100, the injection of the aqueous injection fluid Sint into the well(s) Pu being stopped before the injection of the aqueous injection fluid S2, wherein, for the water-soluble polymer Pint:- the nonionic hydrophilic monomer is selected from the group consisting of: acrylamide, methacrylamide, N-alkyl acrylamides, N-alkyl methacrylamides, N,N-dialkyl acrylamides, N,N-dialkyl methacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol (meth)acrylamide, N-vinylcaprolactam, N-vinylformamide (NVF), N-vinylacetamide, N-vinylimidazole, N-vinylsuccinimide, acryloyl morpholine (ACMO), glycidyl methacrylate, glyceryl methacrylate, diacetone acrylamide, methacrylic anhydride, acrylonitrile, maleic anhydride, itaconic anhydride,itaconamide, vinylpyridine, hydroxyalkyl (meth)acrylates, thioalkyl (meth)acrylates, isoprenol, alkoxylated derivatives of isoprenol, hydroxyethyl (meth)acrylates, alkoxylated derivatives of hydroxy ethyl (meth)acrylates, hydroxypropyl acrylate, alkoxylated derivatives of hydroxypropyl acrylate, vinyl acetate, and mixtures thereof, the alkyl groups being C1-C3 hydrocarbon chains;- the anionic hydrophilic monomer comprising at least one partially or totally salified carboxylic acid function is selected from the group consisting of: acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, C1-C3 itaconic acid hemiesters, crotonic acid, maleic acid, fumaric acid, and mixtures thereof;- the anionic hydrophilic monomer comprising at least one partially or totally salified sulfonic acid function is selected from the group consisting of: allylsulfonic acid, methallylsulfonic acid, 2-methylidenepropane-l,3-disulfonic acid, styrenesulfonic acid, 2- acrylamido-2-methylpropanesulfonic acid (ATBS), 2-acrylamido-2- methylpropanedisulfonic acid, 3-allyloxy-2-hydroxypropanesulfonic acid, and mixtures thereof.

9. Method according to one of the preceding claims, characterised in that:- the total salinity [TDSJi of the saline solution Al is between 1,000 ppm and 330,000 ppm by weight.

10. Method according to one of the preceding claims, characterised in that:- the total salinity [TDSJi of the saline solution A2 is between 100 ppm and 50,000 ppm by weight.

11. Method according to one of the preceding claims, characterised in that:- the total salinity [TDSJint of the saline solution Aint is between 500 ppm and 150,000 ppm by weight.

12. Method according to one of the preceding claims, characterised in that:- the concentration of divalent cations [Div+]i in the salt water Al is between 100 ppm and 30,000 ppm by weight.

13. Method according to one of the preceding claims, characterised in that:- the concentration of divalent cations [Div+]2in the salt water A2 is between 0 ppm and 6,000 ppm by weight.

14. Method according to one of the preceding claims, characterised in that:- the concentration of divalent cations [Div+]int in the salt water Aint is between 100 ppm and 20,000 ppm by weight.

15. Method according to one of the preceding claims, characterised in that: Pl is a polymer of acrylamide and sodium 2-acrylamido-2-methylpropanesulfonate, P2 is a polymer of acrylamide and sodium 2-acrylamido-2-methylpropanesulfonate or a polymer of a polymer of acrylamide and sodium acrylate.

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