Enhanced hydrocarbon recovery process by sequential injection of polymeric compositions

Abstract

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

Description

Title of the invention: Method for enhanced hydrocarbon recovery by sequential injection of polymeric compositions. Field of the invention

[0001] The present invention relates to a method for enhanced recovery of hydrocarbons (oil and / or gas) using a sequential injection sequence of different injection fluids with distinct compositions (nature of the polymer, salinity of the solution). Prior art

[0002] Most of the oil fields currently being exploited have reached maturity and have, in fact, begun to decline in production or are about to do so. The recovery rate (yield) of these fields is currently on the order of 15 to 35% on average relative to the initial quantity of hydrocarbons (oil and / or gas). They therefore still offer considerable production potential.

[0003] Generally, the recovery of hydrocarbons, for example crude oil, contained in deposits is carried out in several stages.

[0004] Production initially results from the natural energy of the decompressing fluids and rock. Following this depletion phase, the quantity of hydrocarbons recovered at the surface represents on average some 5 to 15% of the initial reserve. It is therefore necessary, in a second stage, to employ techniques aimed at increasing the recovery yield while maintaining field pressure.

[0005] The most frequently implemented method consists of injecting water into the reservoir through injection wells specifically designed for this purpose. This is known as secondary recovery. This second phase stops when the water / hydrocarbon ratio becomes too high, that is, when the amount of water in the mixture produced by the production wells is too great. This secondary recovery thus makes it possible to obtain an additional recovery rate of approximately 10 to 20%.

[0006] Other usable techniques are grouped under the name enhanced oil or hydrocarbon recovery (EOR). Their aim is to recover between 10 and 35% more hydrocarbons compared to the initial quantity of hydrocarbons. Under the term enhanced oil or hydrocarbon recovery, various thermal and non-thermal techniques are known, such as electrical, miscible, steam, or chemical techniques for the enhanced recovery of hydrocarbons remaining in place (see "Oil & gas science and technology" - IFP magazine, vol. 63 (2008) no. 1, pp. 9-19).

[0007] The term "petroleum" refers to any type of oil, including light, heavy, and even bituminous oils. An oil generally results from 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 refer to the same substance, except when describing the composition of an emulsion or dispersion.

[0008] The efficiency of water injection sweeping is generally improved by the addition of water-soluble polymers. The expected and proven benefits of using polymers, through the "viscosification" of the injected water, are improved sweeping and a reduction in viscosity contrast between fluids to control their mobility ratio in the field, thereby enabling rapid and efficient hydrocarbon recovery. The most commonly used polymers for increasing water viscosity are acrylamide-based and / or acrylic acid-based and / or 2-acrylamido-2-methylpropanesulfonic acid (ATBS) polymers, and / or their salts.

[0009] Polymers added to injection water are generally subjected to long residence times in the reservoir, between injection wells and production wells, ranging from a few months to a few years. During this time, they can undergo thermal degradation due to an increase in their hydrolysis rate through the conversion of acrylamide units to acrylates, or chemical degradation leading to chain breakage (a decrease in molecular weight) through radical attack. In both cases, these mechanisms generally result in a decrease in viscosity and therefore a loss of efficiency in flushing the underground formation with the injected aqueous polymer solution. There is therefore a real interest in developing polymers more resistant to these processes encountered at enhanced oil and gas recovery sites.

[0010] It is known to those skilled in the art that synthetic water-soluble polymers based on 2-acrylamido-2-methylpropanesulfonic acid (ATBS and / or its salts) or on a monomer functionalized with a sulfonic acid group (and / or their salts) are tolerant to divalent salts and high temperatures. They are therefore advantageously used for injection fluids with high salinity, whereas for low salinity waters, polymers based on acrylamide and acrylic acid can be used.

[0011] The use of low-salinity solutions for preparing water-soluble polymer injection solutions for sweeping operations is generally preferred in the early phases of projects to demonstrate the polymer's effectiveness at pilot scale. The use of production water, which is generally more saline, is then preferred during expansion phases to minimize resource stress. in freshwater. However, in some cases the opposite situation may occur. Examples are given below: The treated wastewater is very often reinjected. However, when it is highly saline (approximately 100 to 280 g / L TDS) and particularly rich in divalent cations, and the reservoir temperature is between 80°C and 140°C, the use of polymers with very high acrylamide sulfonation (ATBS) content is required. This type of polymer represents a significant cost for the project, as its unit cost is generally 20% to 100% higher than that of polymers such as acrylamide and acrylic acid copolymers. Its dosage must also be 15% to 50% higher (by weight). In these specific cases, the use of softer water, whatever its origin (aquifer, softening process), allowing the use of less expensive polymer (lower unit cost and / or dosage) may be preferred in view of the overall cost of the project.This can be particularly the case in some Middle Eastern countries, where large quantities of seawater are softened for drinking water and irrigation. * In the case of sweeping operations requiring the use of alkali (AP: alkali-polymer; ASP: alkali-surfactant-polymer), it is necessary to soften the injection water to prevent the formation of mineral deposits in the presence of alkali. It is therefore common practice to begin with an initial phase of injecting a polymer solution into salt water before proceeding to inject the AP or ASP slug into softened water.

[0012] However, in carbonate reservoirs, and when the injection fluid containing the water-soluble polymer is prepared from a low-salinity 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 quantity of ATBS in the polymer, this calcium ion enrichment can lead to polymer precipitation in the reservoir.

[0013] In this case, the use of polymers based on an ATBS type monomer could be preferred, but these monomers are much more expensive than monomers such as Tacrylamide or acrylic acid, and for a complete sweep campaign of an underground formation where hundreds of tons of polymers may be used, the financial impact is considerable. Description of the invention

[0014] The Applicant has discovered and developed a process for enhanced recovery of hydrocarbons (oil and / or gas) using a sequential injection of different fluids of distinct compositions (nature of the polymer and possibly salinity of the solution) making it possible to avoid the degradation of the injected polymers (makes it possible to reduce the risks of incompatibility or precipitation when injecting an alkaline solution into the reservoir), to optimize hydrocarbon recovery costs and to optimize water resources and therefore to reduce the environmental impact of the assisted recovery operation.

[0015] More specifically, the invention relates to a process for enhanced recovery of hydrocarbons (oil and / or gas) in an underground formation comprising one or more injection wells and one or more production wells, the process comprising at least the following steps: a) prepare an aqueous injection fluid SI by dissolving a polymer PI in salt water Al having a total salinity [TDS] i and a concentration of divalent cations [Div+] i, the PI polymer comprising: - xi mol% of non-ionic hydrophilic monomer, with 0 < xi < 85, - yi mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < yi < 85, and - zi mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with 15 < zi < 100;

[0016] with xi + yi + zi = 100 b) inject the aqueous injection fluid SI into one or more Pu injection wells of an underground formation and sweep the underground formation with this aqueous injection fluid SI; c) prepare an aqueous injection fluid S2 by dissolving a polymer P2 in a salt water A2 having a total salinity [TDS] 2 and a concentration of divalent cations [Div+] 2, with [TDS] 2 < [TDS] ! and [Div+] 2 < [Div+] x / 2, the P2 polymer containing: - x 2 mol% of non-ionic hydrophilic monomer, with 50 < x 2 < 92.5, - y 2 mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < y 2 < 92.5, and - z 2 mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z 2 < zi / 2; with x² + y² + z² = 100 d) stop the injection of the aqueous injection fluid SI; e) inject the aqueous injection fluid S2 into the well(s) Pu and sweep the underground formation with this aqueous injection fluid S2; f) recover an aqueous and hydrocarbon mixture from one or more producing wells of the underground formation.

[0017] In this process, the PI polymer comprises more anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, than the P2 polymer, z2 < zx / 2.

[0018] The injection of the aqueous injection fluid SI is stopped when the subsurface formation exhibits a stabilized resistance factor. The resistance factor corresponds to the force opposing the flow of the fluid in the subsurface formation. In general, this stabilization is advantageously achieved after injecting a quantity of aqueous injection fluid SI between 0.05 and 0.75 times the pore volume of the subsurface formation, more advantageously between 0.1 and 0.4.

[0019] The injection of the first fluid SI and the resulting flushing of the subsurface formation subsequently (step e)) improve the efficiency of the flushing of this subsurface formation by the second fluid S2. The injection of S2, after the formation of an Al / Pl contact front on the rock, which is resistant to reservoir conditions (and expensive), acts as a buffer to allow the injection of a less expensive front (A2 / P2) that may present compatibility problems with reservoir conditions (temperature / salinity) while being fully compatible with the Al / PI front. Without being linked to any specific theory, the injection of the first fluid SI appears to coat the surface of the subsurface rocks with a polymer (PI) layer while improving the control of the injected water's mobility.

[0020] The front corresponds to the transition or contact zone between two fluids injected successively into the underground formation. It is the region where a first fluid (here Al / Pl) comes into contact with the reservoir rock and prepares the way for the injection of a second fluid (here A2 / P2). This front plays a key role in the efficient sweeping 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.

[0021] In the case of carbonate formations, it would appear that this polymer layer formed on the surface of the rock (following the injection of fluid SI) limits and in some cases prevents the release of calcium ions from the rock during its subsequent exposure to less saline water (second fluid S2). The polymer P2 would thus be less subject to divalent ions (risk of polymer precipitation) because these would be released little, or not at all, into the fluid S2.

[0022] In the case of sandstone formations, the injection of the SI fluid appears to offer an additional advantage. Polymers containing sulfonated monomers generally exhibit less adsorption onto the rock than polymers without sulfonated monomers. The PI polymer appears to act as a sacrificial agent from the point of view of adsorption allowing to reduce, or even prevent, the adsorption of the polymer P2 injected into the fluid S2.

[0023] The quantity of aqueous injection fluid S2, injected during step e) is advantageously between 0.05 and 0.85 times the pore volume of the underground formation, more advantageously between 0.15 and 0.55.

[0024] The invention includes all possible combinations of the various disclosed embodiments, whether preferred or given by way of example. Furthermore, where ranges of values ​​are indicated, the bounds are included in those ranges. The disclosure also includes all combinations of the bounds of those ranges of values. For example, the ranges of values ​​"1-20, preferably 5-15" imply the disclosure of the ranges "1-5", "1-15", "5-20", and "15-20", and the values ​​1, 5, 15, and 20.

[0025] The term “polymer” means a homopolymer prepared from a monomer or a copolymer prepared from at least two different monomers.

[0026] Preferably, the PI,P2 polymers used in the process of the invention have (independently of each other) a molecular weight greater than 0.5 million daltons, more preferably between 1 and 40 million daltons, even more preferably between 1 and 30 million daltons, even more preferably between 2 and 20 million daltons, and even more preferably between 3 and 15 million daltons. Molecular weight is understood to be the average molecular weight by weight.

[0027] 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 of plotting the reduced viscosity values ​​(ordinate axis) against the concentration (abscissa axis) and extrapolating the curve down to zero concentration. The intrinsic viscosity value is plotted on the ordinate axis or by using the least squares method. The molecular weight can then be determined by the Mark-Houwink equation: [q] = KM [q] represents the intrinsic viscosity of the polymer determined by the solution viscosity measurement method. K represents an empirical constant. M represents the molecular weight of the polymer, a represents the Mark-Houwink coefficient. K and a depend on the particular polymer-solvent system.

[0028] By "water-soluble polymer" is meant a polymer which gives an aqueous solution without insoluble particles when dissolved under stirring at 25°C and with a concentration of 10 gL 1 in deionized water.

[0029] By "hydrophilic monomer" is meant a monomer which has an octanol / water partition coefficient, Kow, less than or equal to 1, in which the partition coefficient Kow is determined at 25 °C in an octanol / water mixture having a volume ratio of 1 / 1, at a pH between 6 and 8.

[0030] By "hydrophobic monomer" is meant a monomer which has an octanol / water partition coefficient, Kow, greater than 1, in which the partition coefficient Kow is determined at 25 °C in an octanol / water mixture having a volume ratio of 1 / 1, at a pH between 6 and 8.

[0031] Preferably, for PI polymers (when xi 0 ) and P2, independently of each other: - The hydrophilic non-ionic monomers are chosen from the group comprising water-soluble vinyl monomers, preferably from the group consisting of: acrylamide, methacrylamide, N-alkylacrylamides, N-alkylmethacrylamides, N,N-dialkyl acrylamides (for example, N,N-dimethylacrylamide or N,N-diethylacrylamide), N,N-dialkylmethacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol(meth)acrylamide, N-vinyl caprolactam, N-vinylformamide (NVF), N-vinyl acetamide, N-vinyl imidazole, N-vinyl succinimide, acryloyl morpholine (ACMO), the glycidyl methacrylate, glyceryl methacrylate, diacetone acrylamide, methacrylic anhydride, acrylonitrile, maleic anhydride, itaconic anhydride, itaconamide, vinylpyridine, hydroxyalkyl (meth)acrylate, thioalkyl (meth)acrylate, isoprenol,Alkoxylated derivatives of isoprenol, hydroxyethyl(meth)acrylates, alkoxylated derivatives of hydroxyethyl(meth)acrylates, hydroxypropylacrylate, alkoxylated derivatives of hydroxypropylacrylate, vinyl acetate, and mixtures thereof, the alkyl groups being C1-C3 hydrocarbon chains; - hydrophilic anionic monomers comprising at least one carboxylic acid function, partially or totally salified, selected from the group consisting of: acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, the Ci-C3 hemi-esters of itaconic acid, crotonic acid, maleic acid, fumaric acid, and mixtures thereof; - for PI, and for P2 when z 2 0, hydrophilic anionic monomers comprising at least one sulfonic acid function, partially or totally salified, chosen from the group consisting of: allylsulfonic acid, acid methylylsulfonic acid, 2-methylidenepropane-l,3-disulfonic acid, styrene sulfonic acid, 2-acrylamido-2-methylpropane sulfonic acid (ATBS), 2-acrylamido-2-methylpropane disulfonic acid, 3-allyloxy-2-hydroxypropane sulfonic acid, and mixtures thereof.

[0032] The water-soluble salts of the hydrophilic anionic monomers advantageously are salts of alkali metals (preferably sodium or potassium) or of alkaline earth metals (preferably calcium or magnesium) or of ammonium (preferably NH4+).

[0033] Advantageously, for polymers PI and P2 (independently of each other): - for PI when xi 0, and for P2, the hydrophilic non-ionic monomer is acrylamide, - when yi 0 and / or y 2 0, the hydrophilic anionic monomer comprising at least one carboxylic acid function, partially or totally salified, is acrylic acid, - for PI and for P2, the hydrophilic anionic monomer comprising at least one sulfonic acid function, partially or totally salified, is 2-acrylamido-2-methylpropane sulfonic acid.

[0034] Even more advantageously, for the PI and P2 polymers (independently of each other): - for PI when xi 0, and for P2, the hydrophilic non-ionic monomer is acrylamide, - when yi 0 and / or y 2 4 0, the hydrophilic anionic monomer comprising at least one carboxylic acid function is totally salified, is sodium acrylate, - for PI and for P2 when z 2 0, the hydrophilic anionic monomer comprising at least one sulfonic acid function is totally salified, is sodium 2-acrylamido-2-methylpropane sulfonate.

[0035] 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 PI 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.

[0036] Advantageously, the PI polymer is a polymer of ATBS (partially or totally salified) and acrylamide.

[0037] Advantageously, the P2 polymer is a polymer of ATBS (partially or totally salified), acrylamide and acrylic acid (partially or totally salified).

[0038] Advantageously, the process of the invention comprises, between steps d) and e): - the injection into the injection well(s) Pu of an aqueous injection fluid Sint and - the sweeping of the subsurface formation using this fluid Sint, said injection fluid Sint comprising a water-soluble polymer Pint dissolved in saline water Aint having a total salinity [TDS] int and a divalent cation concentration [Div+] int, with [TDS] ≤ [TDS] int < [TDS] i and [Div+] ≤ [Div+] int < [Div+] i, the water-soluble polymer Pint comprising: - x int mol% of non-ionic hydrophilic monomer, with 0 < x int < 92.5, - yint mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < yint < 92.5, and - zint mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z2 <z int <z i et x int + y int + Z int = 100.

[0039] The injection of the fluid Sint into the well(s) Pu is stopped before the injection of the aqueous injection fluid S2.

[0040] The quantity of aqueous injection fluid Sint, injected between steps d) and e) is advantageously between 0 and 0.5 times the pore volume of the underground formation, more advantageously between 0.05 and 0.3.

[0041] The Pint polymer preferably has a molecular weight of at least 0.5 million daltons, more preferably between 1 and 40 million daltons, even more preferably between 1 and 30 million daltons, even more preferably between 2 and 20 million daltons, and even more preferably between 3 and 15 million daltons. The molecular weight is understood to be the average molecular weight by weight and is measured as indicated above for the PI and P2 polymers.

[0042] The PI, P2 and Pint polymers exhibit (independently of each other) a salification rate of the anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, advantageously between 30% and 100%, relative to the number of carboxylic acid functions.

[0043] The PI, P2 and Pint polymers exhibit (independently of each other) a salification rate of the anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, advantageously between 30% and 100%, relative to the number of sulfonic acid functions.

[0044] The monomers of the Pint polymer are preferably chosen from the same lists as those of the PI and P2 polymers. The preferred monomers of PI and P2 are advantageously those of Pint.

[0045] Preferably, the Sint fluid contains between 0.1% and 2% by weight (relative to the weight of the Sint fluid) of Pint polymer.

[0046] Optionally, the PI, P2 and Pint polymers may contain less than 1 mol% of hydrophilic cationic monomers and / or hydrophilic zwitterionic monomers and / or hydrophobic monomers.

[0047] The polymers used in the process of the invention (PI, P2 and optionally Pint) can have (independently of each other) a linear, branched, ramified, star-shaped or comb-shaped structure. This structure can be obtained, according to the general knowledge of a person skilled in the art, for example by selecting the initiator; the transfer agent; the concentration; or the polymerization technique such as reversible addition-fragmentation chain transfer polymerization (RAFT), nitroxide-mediated polymerization (NMP) or atom transfer radical polymerization (ATRP), or by incorporating structural monomers.

[0048] Polymers can also be structured by a branching agent. A structured polymer is defined as a non-linear polymer that has side chains.

[0049] The branching agent is advantageously chosen from: - Structuring agents, which may be chosen from the group comprising polyethylene unsaturated compounds (having at least two unsaturated functions), such as vinyl functions, particularly allylic or acrylic, and examples include methylene bisacrylamide (MBA), triallyamine, or tetraallylammonium chloride or 1,2-dihydroxyethylene bis-(N-acrylamide), - Compounds having at least two epoxy functions, - Compounds having at least one unsaturated function and one epoxy function, - Macroinitiators such as polyperoxides, polyazo compounds, and polytransfer agents such as polymer-capturing polymers and polyols, - Functionalized polysaccharides, - water-soluble metal complexes composed of: * of a metal with a valence greater than 3 such as, by way of example and without limitation, aluminium, boron, zirconium or titanium, and * of a ligand bearing a hydroxyl function.

[0050] The amount of branching agent in the polymers is advantageously less than 1000 ppm by weight relative to the total weight of the polymer monomers, preferably less than 100 ppm by weight, and more preferably less than 10 ppm by weight. When a branching agent is used, its amount is advantageously at least 1 ppm.

[0051] Water-soluble polymers comprising at least one branching agent remain water-soluble. A person skilled in the art will know how to adjust the amount of branching agent, and possibly the amount of transfer agent, to achieve this result.

[0052] In a particular mode, the PI, P2 and Pint polymers do not include a branching agent.

[0053] The PI polymer comprises xi mol% of non-ionic hydrophilic monomer, with xi between 0 and 85 and more preferably between 10 and 80.

[0054] The polymer P2 comprises x 2 mol% of non-ionic hydrophilic monomer, with x 2 between 50 and 92.5, preferably between 55 and 85%, and even more preferably between 60% and 85%.

[0055] The Pint polymer comprises x int mol% of non-ionic hydrophilic monomer, with x int between 0 and 92.5, preferably between 5 and 92.5, and even more preferably between 10 and 90.

[0056] The PI polymer comprises yi mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with yi between 0 and 85, preferably between 10 and 25, and even more preferably between 10 and 15.

[0057] The polymer P2 comprises y 2 mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with y 2 between 0 and 92.5, preferably between 15 and 70, and even more preferably between 20 and 50.

[0058] The Pint polymer comprises y int mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with y int between 0 and 92.5, preferably between 0 and 70, and even more preferably between 0 and 50.

[0059] The PI polymer comprises zi mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with zi between 15 and 100, advantageously between 10 and 90, preferably between 15 and 90, and even more preferably between 20 and 90.

[0060] The polymer P2 comprises z 2 mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z 2 less than 50%, more preferably less than 30%.

[0061] The Pint polymer comprises z int mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z2 <z int<Zi

[0062] The PI, P2 and Pint polymers used to prepare the SI, S2 and Sint solutions can be (independently of each other) in liquid form or in the form solid. 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 emulsions.

[0063] In the formation of aqueous injection fluids SI, S2 and Sint, the dissolution of the polymer in salt water includes the mixing of the polymer (in any form) and salt water, for example the mixing of the polymer in the form of an inverse emulsion and salt water or the mixing of the polymer in the form of a powder and salt water.

[0064] When polymers are in solid form (advantageously powder), they can be partially or totally dissolved in aqueous solution to obtain fluids SI, S2 or Sint using a polymer preparation unit such as the Polymer Slicing Unit (PSU) disclosed in document EP 2 203 245.

[0065] The injection fluids (SI, S2, and Sint) contain the polymers (PI, P2, and Pint) and, depending on the technique used, one or more chemical compounds useful for enhanced hydrocarbon recovery. These chemical compounds include the use of weak, strong, or super-strong mineral or organic bases capable of saponifying crude hydrocarbons and forming hydrocarbon-solubilizing surfactants in situ. Examples include sodium carbonate, caustic soda (NaOH), borate compounds, metaborate compounds, amines, basic polymeric species, and mixtures thereof. Another family of compounds commonly injected with the polymers is that of surfactants, often anionic, zwitterionic, cationic, and sometimes also nonionic. These compounds are rarely injected pure but with a co-surfactant and a co-solvent to improve their compatibility and efficiency in the reservoir.

[0066] The salt waters Al, A2 and Aint are prepared (independently of each other) 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, aluminum 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.

[0067] The salt waters Al, A2 and Aint preferably contain at least one of the following: sodium chloride, calcium chloride, sodium bromide, calcium bromide, zinc bromide, sodium formate and potassium formate.

[0068] Preferably, the total salinity [TDS] i of the salt solution Al (weight concentration) is between 1,000 ppm and 330,000 ppm.

[0069] Preferably, the total salinity [TDS] 2 of the salt solution A 2 (concentration by weight) is between 100 ppm and 50,000 ppm.

[0070] Preferably, the total salinity [TDS] int of the salt solution Aint (concentration by weight) is between 500 ppm and 150,000 ppm.

[0071] Preferably, the concentration of divalent cations [Div+] i (by weight) in the salt water Alest is between 100 ppm and 30,000 ppm.

[0072] Preferably, the concentration of divalent cations [Div+] 2 (by weight) in the salt water A2 is between 0 ppm and 6,000 ppm.

[0073] Preferably, the concentration of divalent cations [Div+] int (by weight) in the salt water Aintest between 100 ppm and 20,000 ppm.

[0074] The invention and its advantages will become clearer from the following figures and examples, which are given to illustrate the invention, but are not limited to these examples. Figures

[0075] [Fig-1] The [Fig. 1] illustrates the variation of the resistance factor of a core from an underground formation as a function of the injected quantity of polymer expressed in pore volume equivalents of the core.

[0076] [Fig.2] Fig.2 illustrates the turbidity of a polymer solution in desalinated seawater aged for 7 days at 120°C as a function of calcium concentration.

[0077] [Fig.3] Fig.3 illustrates the evolution of the residual viscosity of polymer solutions during their aging at 80°C under anaerobic conditions.

[0078] [Fig.4] Fig.4 illustrates the evolution of the resistance factor of a sandstone rock as a function of the injected quantity of polymer expressed in pore volume equivalents of the sandstone rock. Examples

[0079] Example No. 1: Case of a carbonate reservoir at high temperature and high salinity

[0080] The tests below were carried out on cores of carbonate reservoir rock from the Middle East, with a permeability of approximately 150 mD. Each core was saturated with formation water having a total salinity of 236 g / L and a divalent cation concentration of 16.5 g / L (see composition in Table 2) at a temperature of 120°C. The two scenarios described in Table 1 were compared.

[0081] The Pl-1 polymer is a sodium ATBS polymer (70 mol%, totally salified ATBS) and acrylamide (30 mol%).

[0082] The Pint polymer is identical to the Pl-1 polymer.

[0083] The P2-1 polymer is a sodium ATBS polymer (25 mol%, totally salified ATBS) and acrylamide (75 mol%), therefore having an anionicity of 25 mol%.

[0084] [Tables 1] Scenario Sequence #1 Polymer Pl-1 Ai = Production water (236 g / L TDS) Sequence #2 Polymer Pint Aint ----- Seawater (42 g / L TDS) ___ Sequence #3 Polymer P2-1 A2 = Desalinated seawater (241 ppm TDS) Scenario #2 Sequence #1 Polymer P2-1 A2 = Desalinated seawater (241 ppm TDS)

[0085] Table 1: Injection scenarios in carbonate reservoir rock.

[0086] [Tables2] Salts Pradaeliàn Al Sea Water Aint Desalinated Sea Water A2 N aCI (g / L) 2 £4.9 28.6 0.22 KCî (g / L) 347 0.00 0.ÜL CaCL. 21 LC (g / L) 54.6 1.90 ÿ.üv MgCij. 13 7 LU 02 MaHCQ, (g / L.) 0.00 0.23 0.00 (>'L) 0.16 4 §4 0.00 TDS (g / I) 236.1 41.6 0.24 Divalent Cations (g / L) 16.5 2.18 0.00 Carbonates (g / L) 0.00 ■3.17 0.00 R- 0.12 0.14 0.03

[0087] Table 2: Composition of the salt waters Al, Aint and A2 of example 1.

[0088] The results obtained according to scenarios #1 and #2 are illustrated by [Fig.1].

[0089] Al and Pl-1 form fluid SI. Aint and Pint form fluid Sint. A2 and P2-1 form the fluid S2 -1.

[0090] * Summary of scenario #1:

[0091] - Sequence #1 (Sce. #1 - Seq. #1 : SI = 14.5 pore volumes): Injecting the Pl-1 polymer at 2000 ppm (by weight) into the production water in a core sample at 120°C leads to a rapid stabilization of the strength factor at a value of approximately 10 ± 0.2 after injecting a quantity of fluid (SI₂) equivalent to slightly less than 2.5 times the core pore volume. This indicates excellent injectivity / propagation of the polymer in the porous medium.

[0092] - Sequence #2 (Sce. #1 - Seq. #2: Sint = 7 pore volumes): After injecting a quantity of fluid (SI) equivalent to 14.5 times the core pore volume, the transition to injection (Sint) of the polymer Pint at 1500 ppm (concentration adjusted to maintain the same injected viscosity) in seawater at 42 g / L TDS (Aint) leads to a slight increase in the resistance factor from approximately 10 to a value of around 11.2. Despite maintaining the same injected viscosity, it is suspected that the change in salinity causes swelling of the adsorbed polymer layer formed during sequence #1 at higher salinity, leading to this increase in the resistance factor. This transition occurs After injecting a quantity of fluid (Sint) equivalent to approximately less than twice the pore volume of the core, the resistance factor remains stable during the injection of an additional quantity of fluid (Sint) equivalent to five times the pore volume of the core. This behavior further illustrates the good injectivity of the polymer solution under these conditions.

[0093] - Sequence #3 (Sce. #1 - Seq. #3: S2 = 11 pore volumes): After 21.5 pore volumes (SI + Sint), switching to injecting the P2-1 polymer at 800 ppm into desalinated seawater at 241 ppm TDS (S2) led to a more significant increase in the resistance factor, from 11.2 to approximately 18. Again, the polymer concentration was adjusted to maintain the same injected viscosity. Similarly, the increase in the resistance factor is attributed to swelling of the adsorbed polymer layer due to the decreasing salinity. The much greater salinity contrast between sequence #2 and sequence #3, compared to that between sequences #1 and #2, explains the larger increase in the resistance factor resulting from the swelling of the adsorbed polymer layer.The resistance factor then remains stable during the injection of an additional quantity of fluid (S2) equivalent to 10 times the pore volume of the core, indicating that the polymer solution presents no injectivity problems under these conditions.

[0094] * Summary of scenario #2 (Sce. #2: S2 = 13 pore volumes):

[0095] The P2-1 polymer used in sequence #3 of scenario #1 has this time been Fluid (S2) is injected directly at 800 ppm into seawater desalinated at 241 ppm TDS in the core. Initially, an increase in the resistance factor is observed after the injection of a quantity of fluid (S2) equivalent to 5 times the core pore volume, 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 quantity of fluid (S2) equivalent to 1 to 2 times the core pore volume, the resistance factor increases linearly with the quantity of fluid (S2) injected, expressed as equivalent core pore volumes. This behavior is attributed to: * on the one hand, to a rapid increase in the rate of hydrolysis of the polymer under the effect of temperature, with a conversion of acrylamide units into sodium acrylate, and * on the other hand, to a release of calcium by the carbonate rock exposed to desalinated seawater A2 of very low salinity.

[0096] Fig. 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.

[0097] To illustrate this last point (release of calcium by carbonate rock), core samples were subjected to injections of fluids of different salinities: * Virgin reservoir rock exposed to formation water injection at 236 g / L TDS * Reservoir rock containing pre-adsorbed Pl-1 polymer (Pl-1 polymer injection carried out in formation water according to scenario #1 sequence #1; SI) exposed to desalinated seawater injection at 241 ppm TDS (A2) * Virgin reservoir rock exposed to the injection of desalinated seawater at 241 ppm TDS (A2).

[0098] The levels of calcium ions released into the effluents during each sequence were determined by ICP-MS and are reported in Table 3.

[0099] [Tables3] Calcium enrichment, re-aggregated water, 236 g / L TDS (Al) Not detectable. Desalinated water at 241 ppm TDS (Al2j) in the presence of a pre-adsorbed Pi-1 potassium layer (Si) Not detectable. Desalinated water at 241 ppn TDS (Al2j) 706 ppm

[0100] Table 3: Calcium release tests from reservoir rock as a function of injected fluid.

[0101] It was not possible to detect any release of calcium from the reservoir rock when it was exposed to the formation water flow (Al). Similarly, when the rock was previously coated with polymer Pl-1 (Si), its subsequent exposure to highly desalinated water, in this case seawater desalinated at 241 ppm TDS (A2), did not result in the detection of calcium released from the rock into the effluent. Conversely, in the case of a pristine rock sample, the calcium release rate upon exposure to a desalinated seawater flow (A2) was measured to be on the order of 700 ppm. In this case, the presence of a pre-adsorbed layer of polymer Pl-1 very strongly limits, if not inhibits, the release of calcium into solution.

[0102] In addition, the P2-1 polymer was subjected to aging at 120°C for 7 days in desalinated seawater (A2), followed by controlled additions of calcium while monitoring the turbidity of the polymer solution as a function of the added calcium concentration. According to the results shown in [Fig. 2], the turbidity begins to increase sharply at 175 ppm of released calcium, indicating a compatibility issue between the polymer and the calcium present in the solution.

[0103] 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.

[0104] These tests demonstrate the advantage of sequential injection. The first step consists of injecting a polymer resistant to harsh conditions, in this case, a carbonate rock saturated with formation water of very high salinity (A2, 236 g / L) and at very high temperature (120°C). This first injection forms a protective film that prevents the release of calcium from the reservoir rock upon its subsequent exposure to water of very low salinity. This protective film then allows, in a second step, the injection of a less robust and, therefore, more economical polymer at a significantly lower concentration. This sequence ensures good injectivity and efficient transport of the polymer solutions within the porous medium.An intermediate step can also be added, consisting of injecting an intermediate polymer Pint between Pl-1 and P2-1 into water of intermediate salinity, to reduce the risk of incompatibility during a too abrupt change in the salinity of the injection water.

[0105] On the contrary, the direct injection of the P2-1 polymer into low salinity water quickly leads to irreversible damage to the porous medium due to the incompatibility between the P2-1 polymer, which hydrolyzes during its stay in a porous medium at 120°C, and the release of calcium from the reservoir rock exposed to low salinity water, which leads to the precipitation of the polymer.

[0106] Example No. 2: Case of a sandstone reservoir at a relatively high temperature in the presence of divalent cations

[0107] In the case of a sandstone reservoir with a permeability of the order of 1200 mD, a water salinity of 50 g / L TDS and a temperature of the order of 80°C, the most suitable polymer is the P2-1 polymer (75 mol% acrylamide (AM) and 25 mol% ATBS) (SPAM), the P2-2 copolymer (70 mol% acrylamide and 30 mol% sodium acrylate (AA)) (HPAM) not offering the required stability under these conditions, as illustrated in [Fig.3].

[0108] On the other hand, in the case of using water with 30 g / L 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 point of view because of a lower unit price than an ATBS-based polymer but also because of a lower dosage to achieve the same viscosity value due to the reduction in salinity.

[0109] [Tables4] Salts Water 50 g / L Water 30 g / L _________________________ KCl (g / L) ........gcOOcçu........ ___________ 44.9J,____________ ___________0.47_ __________ 5.80 30 0 0.00 ^¾. 6ILO (g / L) (g / L) Na,S(ÿ, f eÆA 2.95 _........O.0Ï........... oie 0.00 __________0. Î5 ________ ' ...... ~d.ôd ...........TDSJgJj........... Divalent Cations (g / L) Cgibünates (g / L) ..........JJ .33,.......... Ï.98 ........30 J?......... 0.08 IC 0.10 0.00

[0110] Table 4: Composition of the salt waters Al, Aint and A2 of example 2. [YES] [Tables5] Polymer Type AM (mol%) [ ÀA (tnoi%) j \ I BS (mol%) P2-1 SPAM 75% ji 25% P2-2 HP AM '70% | 30% |

[0112] Table 5: Composition of polymers used in example no. 2.

[0113] Fig. 3 illustrates the evolution of the residual viscosity of solutions of polymers P2-1 and P2-2 prepared at isoviscosity in production water (Al, 50 g / L) and in seawater (30 g / L) over time during their aging at 80°C under anaerobic conditions.

[0114] Figure 4 shows the sequential injections of polymer P2-1 prepared in 50 g / L TDS brine, followed by polymer P2-2 prepared in 30 g / L TDS brine at isoviscosity into a sandstone core from the reservoir with a permeability of approximately 1200 mD. These injections, carried out at an injection rate of 61 cm / day, indicate very good injectivity and propagation of the polymer solutions.

[0115] 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 a rock core that is initially untreated and saturated with brine. The first polymer front is delayed by polymer adsorption. When the polymer concentration at the core outlet is identical to the injected concentration, polymer adsorption onto the rock has been achieved. A brine front is then injected (an amount equivalent to 50 to 100 times the core pore volume) to remove all unadsorbed polymer from the core. A second polymer front is then injected; this one is no longer delayed, as adsorption has already been achieved. The difference between the two fronts then allows the amount of polymer adsorbed onto the rock to be determined.

[0116] We also did the same in the case of injecting a first front of the P2-1 polymer into the 50 g / L TDS brine followed by a second front but of the P2-2 polymer in brine 30 g / L TDS. The results obtained are reported in Table 6.

[0117] [Tableauxô] | Exp. Front 1 Front! Adsorption Front 3 I Snr-Ads. ! 1 #1 P2-1 f5Ü g / L TDS) P2-1 <'50 £l TDS) 25 pg / g 1 ' । P2-2 P2-2 139 Lt^g Aû £1 TDS) (30 fc'L TD.S'j । P2-1 <50s?L TDS,T P2-1 (50 g / L TDS) 26 pg'g P2-2 (30g / L TDS} I - S PS-'gj

[0118] Table 6: Adsorption values ​​measured by the two-front method in the case of the injection of the P2-1 polymer prepared in 50 g / L TDS brine, of the injection of the P2-2 polymer prepared in 30 g / L TDS brine and during the injection of the P2-2 polymer prepared in 30 g / L TDS brine and injected after an injection of the P2-1 polymer prepared in 50 g / L TDS brine.

[0119] In the case of polymer P2-1 alone (#1), the adsorption value obtained is relative, measured at 25 pg of polymer per gram of rock. In the case of polymer P2-2 (#2) alone in 30 g / L TDS brine, the adsorption value obtained is much higher, measured at 139 pg / g of polymer per gram of rock. Finally, in the case of polymer P2-2 injected into 30 g / L TDS brine after pre-injection of polymer P2-1 into 50 g / L brine (#3), no over-adsorption of polymer P2-2 is detected.

[0120] The strong adsorption of polymer P2-2 is explained by the relatively high clay content in the reservoir rock and by the polymer's composition, as AM / AA copolymers are known to be particularly sensitive to the presence of clay in sandstone, from a tadsorption perspective. Conversely, the presence of ATBS in polymer P2-1 significantly minimizes this impact and reduces tadsorption in the presence of clay. This has already been reported in the literature, as in the work of Seright et al. (RS Seright, 2023). Interestingly, pre-adsorption of polymer P2-1 prevents the adsorption of subsequently injected polymer P2-2, while exhibiting a much lower adsorption rate than directly injected polymer P2-2.

[0121] These results confirm the advantages of injecting different polymers sequentially. Injecting a first, more robust polymer tolerant to high salinity, generally corresponding to the formation water or the produced water that is reinjected, allows for a transition to a less robust but more economical polymer by injecting less saline water, which could be treated (desulfated) seawater or any other fresher water source (river, aquifer, water from another field or formation), given that this polymer would not have been stable in the formation or produced water. This strategy also minimizes tadsorption of the polymer, particularly in the presence of of clayey rocks. This type of transition is found in particular in Alkaline-Polymer or Alkaline-Surfactant-Polymer processes in which it is necessary to use softened water, less salty than the injection water used previously.

Claims

1. Demands Enhanced hydrocarbon recovery process in an underground formation comprising one or more injection wells and one or more production wells, the process comprising at least the following steps: a) prepare an aqueous injection fluid SI by dissolving a polymer PI in salt water Al having a total salinity [TDS] i and a divalent cation concentration [Div+] i, the polymer PI comprising: - xi mol% of nonionic hydrophilic monomer, with 0 < xi < 85, - yi mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < yi < 85, and - zi mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with 15 < zi < 100; with xi + yi + zi = 100 b) inject the aqueous injection fluid SI into one or more injection wells Pu of an underground formation and sweep the underground formation with this aqueous injection fluid SI; c) prepare an aqueous injection fluid S2 by dissolving a polymer P2 in a salt water A2 having a total salinity [TDS] 2 and a concentration of divalent cations [Div+] 2, with [TDS] 2 < [TDS]! and [Div+] 2 < [Div+] x / 2, the P2 polymer containing: - x 2 mol% of non-ionic hydrophilic monomer, with 50 < x 2 < 92.5, - y 2 mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < y 2 < 92.5, and - z 2 mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z 2 < zi / 2; with x² + y² + z² = 100 d) stop the injection of the aqueous injection fluid SI;

2.

3. e) inject the aqueous injection fluid S2 into the well(s) Pu and sweep the underground formation with this aqueous injection fluid S2; f) recover an aqueous and hydrocarbon mixture from one or more producing wells of the underground formation. A process according to claim 1, characterized in that the PI and P2 polymers have average molecular weights by weight greater than 0.5 million daltons. A process according to any one of the preceding claims, characterized in that, for the polymers PI (xi 0) and P2: - the hydrophilic non-ionic monomers are chosen from the group consisting of: acrylamide, methacrylamide, N-alkylacrylamides, N-alkylmethacrylamides, N,N-dialkylacrylamides, N,N-dialkylmethacrylamides, alkoxylated esters of acrylic acid, alkoxylated esters of methacrylic acid, N-vinylpyrrolidone, N-methylol(meth)acrylamide, N-vinyl caprolactam, N-vinylformamide (NVF), N-vinyl acetamide, N-vinyl imidazole, N-vinyl succinimide, acryloyl morpholine (ACMO), glycidyl methacrylate, glyceryl methacrylate, acrylamide diacetone, 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 CrC3 hydrocarbon chains; - hydrophilic anionic monomers comprising at least one carboxylic acid function, partially or totally salified, selected from the group consisting of: acrylic acid, methacrylic acid, dimethylacrylic acid, itaconic acid, the Ci-C3 hemi-esters of itaconic acid, crotonic acid, maleic acid, fumaric acid, and mixtures thereof; - hydrophilic anionic monomers comprising at least one sulfonic acid function, partially or totally salified, selected from the group consisting of: allylsulfonic acid, methallylsulfonic acid, 2-methylidenepropane-1,3- disulfonic acid, styrene sulfonic acid, 2-acrylamido-2-methylpropane sulfonic acid (ATBS), 2-acrylamido-2-methylpropane disulfonic acid, 3-allyloxy-2-hydroxypropane sulfonic acid, and mixtures thereof.

4. A process according to any one of the preceding claims, characterized in that, for the polymers PI and P2: - - for PI when xi 4 0, and for P2, the hydrophilic nonionic monomer is acrylamide, - when yi 4 0 and / or y 2 4 0, the hydrophilic anionic monomer comprising at least one carboxylic acid function, partially or totally salified, is acrylic acid, - for PI and for P2, the hydrophilic anionic monomer comprising at least one sulfonic acid function, partially or totally salified, is 2-acrylamido-2-methylpropane sulfonic acid.

5. A process according to any one of claims 1 to 4, characterized in that, for polymers PI and P2: - for PI when xi 4 0, and for P2, the hydrophilic nonionic monomer is acrylamide, - when yi 4 0 and / or y 2 4 0, the hydrophilic anionic monomer comprising at least one carboxylic acid function is totally salified, is sodium acrylate, - for PI and for P2 when z 2 4 0, the hydrophilic anionic monomer comprising at least one sulfonic acid function is totally salified, is sodium 2-acrylamido-2-methylpropane sulfonate.

6. A process according to any one of the preceding claims, characterized in that the aqueous injection fluid SI contains between 0.1% and 2% by weight of polymer PI and in that the aqueous injection fluid S2 contains between 0.1% and 2% by weight of polymer P2.

7. A method according to any one of the preceding claims, characterized in that the method comprises, between steps d) and e): - the injection into the injection well(s) Pu of an aqueous injection fluid Sint and - the sweeping of the subsurface formation with this fluid Sint, said aqueous injection fluid Sint comprising a water-soluble polymer Pint dissolved in a saline water Aint having a total salinity [TDS] int and a divalent cation concentration [Div+] int, with [TDS] 2 < [TDS] int < [TDS] x and [Div+] 2 < [Div+] int < [Div+] i, the water-soluble polymer Pint comprising: - x int mol% of nonionic hydrophilic monomer, with 0 < x int < 92.5, - y int mol% of anionic hydrophilic monomer comprising at least one carboxylic acid function, partially or totally salified, with 0 < y int < 92.5, and - z int mol% of anionic hydrophilic monomer comprising at least one sulfonic acid function, partially or totally salified, with z 2 <z int <z i et x int + y int + z int = 100, l’injection du fluide d’injection aqueux Sint dans le ou les puit(s) Pu étant stoppée avant l’injection du fluide d’injection aqueux S2.

8. A process according to any one of the preceding claims, characterized in that: - the total salinity [TDS] i of the salt solution Al is between 1,000 ppm and 330,000 ppm by weight, - the total salinity [TDS] 2 of the salt solution A2 is between 100 ppm and 50,000 ppm by weight, - the total salinity [TDS] int of the salt solution Aint is between 500 ppm and 150,000 ppm by weight.

9. A process according to any one of the preceding claims, characterized in that: - the concentration of divalent cations [Div+] i in salt water Al is between 100 ppm and 30,000 ppm by weight, - the concentration of divalent cations [Div+] 2 in salt water A2 is between 0 ppm and 6,000 ppm by weight, - the concentration of divalent cations [Div+] int in salt water Aint is between 100 ppm and 20,000 ppm by weight.

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