A pH response mine water reinjection injection enhancer and method for water-rock interface lubrication

Abstract

The application provides a mine water recharging and injection agent and a method for increasing injection at a water-rock interface, wherein the injection agent comprises: hydrophilic inorganic nanoparticles; a coupling agent; and a polymer, which is grafted to the surface of the hydrophilic inorganic nanoparticles through the coupling agent, and the polymerized monomers of the polymer comprise pH-sensitive monomers containing carboxyl or amino groups and quaternary ammonium salt cationic monomers, so that the chain of the polymer shrinks in an acid condition or a neutral condition, and expands and connects to a wall surface to be treated in an alkaline condition. The injection agent in the application can be transported first and then attached, has a low loss rate and strong adhesion.

Description

Technical Field

[0001] This application relates to the field of injection enhancement agents, and in particular to a pH-responsive mine water reinjection enhancement agent and injection method for water-rock interface lubrication. Background Technology

[0002] Conventional injection enhancers are often adsorbed along their migration path before reaching the deep target reservoir during injection, resulting in significant agent loss and low effective utilization. Furthermore, these enhancers only bind to the rock surface through weak physical interactions, resulting in poor interfacial adhesion and weak erosion resistance. Under long-term water injection and high-velocity erosion, they are easily desorbed and lost with the water flow, making it difficult to form a stable and long-lasting protective layer on the surface of formation fissures. Ultimately, this leads to a rapid decline in the enhancement effect and a short-term rebound in injection pressure. Summary of the Invention

[0003] In view of this, the purpose of this application is to propose a pH-responsive mine water reinjection enhancer and injection method for water-rock interface lubrication, so as to solve the problem of easy loss and leakage of existing enhancers.

[0004] To achieve the above objectives, this application provides a pH-responsive mine water reinjection enhancer for water-rock interface lubrication, comprising:

[0005] Hydrophilic inorganic nanoparticles; Coupling agents; A polymer is grafted onto the surface of the hydrophilic inorganic nanoparticles via the coupling agent. The polymer monomers include pH-sensitive monomers containing carboxyl or amino groups and quaternary ammonium salt cationic monomers, so that the polymer chains coil and shrink under acidic or neutral conditions, and stretch and connect to the wall surface to be treated under alkaline conditions.

[0006] Optionally, the polymer monomers may further include anionic monomers containing sulfonic acid groups and acrylamide monomers.

[0007] Optionally, the mass ratio of the pH-sensitive monomer containing carboxyl or amino groups, the quaternary ammonium salt cationic monomer, the anionic monomer containing sulfonic acid groups, and the acrylamide monomer is (0.5-1.5):(0.5-1.5):(2-4):(5-7).

[0008] Optionally, the pH-sensitive monomer containing carboxyl or amino groups includes one or more of acrylic acid, methacrylic acid, itaconic acid, maleic acid, fumaric acid, ethyl aminoacrylate, and methyl aminomethacrylate.

[0009] Optionally, the quaternary ammonium salt cationic monomer includes one or more of methacryloyloxyethyltrimethylammonium chloride, acryloyloxyethyltrimethylammonium chloride, dimethyl diallyl ammonium chloride, methacrylamidopropyltrimethylammonium chloride, and vinylbenzyltrimethylammonium chloride.

[0010] Optionally, the sulfonic acid-containing anionic monomer includes one or more of 2-acrylamido-2-methylpropanesulfonic acid, sodium propylene sulfonate, sodium methpropylene sulfonate, sodium styrene sulfonate, and sodium vinyl sulfonate.

[0011] Optionally, the acrylamide monomer includes one or more of acrylamide, N-methylacrylamide, N-ethylacrylamide, N-isopropylacrylamide, N,N-dimethylacrylamide, N-hydroxymethylacrylamide, and N-tert-butylacrylamide.

[0012] Optionally, the hydrophilic inorganic nanoparticles include one or more of the following: silica nanoparticles, titanium dioxide nanoparticles, alumina nanoparticles, zinc oxide nanoparticles, hydroxyapatite nanoparticles, montmorillonite nanoparticles, and zeolite nanoparticles.

[0013] Based on the same inventive concept, this disclosure proposes an injection-enhancing working fluid, comprising the aforementioned injection enhancer, solution, and additives.

[0014] Based on the same inventive concept, this disclosure proposes a method for increasing mine water injection, comprising: Remove dirt from the wall surface to be treated, wherein the wall surface to be treated is the wall surface of the formation fissure; The pH of the booster working solution is adjusted to acidic to obtain an acidic booster working solution. After the acidic injection fluid is injected into the formation fractures, the pH of the acidic injection fluid is adjusted to alkaline. Mine water is injected into the fissures in the formation.

[0015] As can be seen from the above, the additive provided in this application uses a coupling agent to graft polymers onto the surface of inorganic nanoparticles in the form of chemical bonds, which can significantly improve the structural stability of the particles under high mineralization, high temperature and high-speed shear conditions, and avoid polymer layer detachment and nanoparticle aggregation. The polymer chain simultaneously introduces carboxyl or amino pH-sensitive groups and quaternary ammonium salt cationic groups, synergistically achieving pH-responsive intelligent transport and anchoring: when the additive is in an acidic environment, the carboxyl groups on the pH-sensitive groups exist in the form of -COOH, or as protonated -NH3. +In its current form, the charges within the chain segments attract each other, and the molecular chains are tightly coiled. At this point, the hydrated particle size is small, the surface charge density is low, and the overall particle is electrically neutral or weakly charged, possessing excellent deep migration capabilities. It can smoothly pass through the pore throat and reach the treatment wall location in the formation fissure. When the injector reaches the target location, it switches to an alkaline environment, and a large number of carboxyl groups dissociate into negatively charged carboxylate groups, while amino groups lose protons and become neutral. The negative charge within the chain segments increases significantly and exceeds the positive charge of the quaternary ammonium salt, generating a strong electrostatic repulsion force within the chain, allowing the coiled polymer chain segments to fully unfold. At the same time, the quaternary ammonium salt cationic groups can form strong electrostatic adsorption with the negatively charged rock and clay surfaces, allowing the particles to be firmly anchored to the pore throat wall, forming a stable and dense protective layer, thereby achieving the targeted injector effect of "first migration, then fixation". Attached Figure Description

[0016] To more clearly illustrate the technical solutions in this application or related technologies, the drawings used in the description of the embodiments or related technologies will be briefly introduced below. Obviously, the drawings described below are only embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0017] Figure 1 This is a comparison chart of the long-term reinjection pressure stability of different systems in the embodiments of this application; Figure 2 These are SEM images of the core wettability and pore throat structure before and after processing in the embodiments of this application. Figure 3 This is a comparison diagram showing the core-shell chemical grafting structure and the physical composite structure in the embodiments of this application; Figure 4 This application provides a schematic diagram illustrating the pH-responsive smart migration-anchoring mechanism in its embodiments. Detailed Implementation To make the objectives, technical solutions, and advantages of this application clearer, the following detailed description is provided in conjunction with specific embodiments and the accompanying drawings.

[0018] It should be noted that, unless otherwise defined, the technical or scientific terms used in the embodiments of this application should have the ordinary meaning understood by one of ordinary skill in the art to which this application pertains. The terms "first," "second," and similar terms used in the embodiments of this application do not indicate any order, quantity, or importance, but are merely used to distinguish different components. Terms such as "comprising" or "including" mean that the element or object preceding the word encompasses the elements or objects listed after the word and their equivalents, without excluding other elements or objects. Terms such as "connected" or "linked" are not limited to physical or mechanical connections, but can include electrical connections, whether direct or indirect. Terms such as "upper," "lower," "left," and "right" are only used to indicate relative positional relationships; when the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0019] As described in the background section, deep, low-permeability sandstone reservoirs are the primary target formations for mine water reinjection and oil and gas field water injection development. These reservoirs are generally characterized by small pores, low permeability, and strong heterogeneity, and are rich in water-sensitive clay minerals such as montmorillonite and illite. During long-term reinjection and water injection, clay minerals are prone to hydration, expansion, dispersion, and migration upon contact with water, causing pore throat narrowing and formation blockage. This leads to a continuous increase in injection pressure and a rapid decline in injection capacity, severely restricting the safe and efficient reinjection of mine water and the long-term stable operation of the formation.

[0020] To improve reservoir permeability and enhance water injection capacity, injection enhancement agents have become the mainstream technology for enhanced water injection. The core function of these agents is to reduce water flow resistance and inhibit formation damage through the wetting reversal, pore-throat unblocking, and clay swelling prevention functions of nanoparticles, thereby achieving the goal of pressure-reducing injection and extending the effective injection cycle. However, most existing conventional injection enhancement agents are nanoparticles, which have significant technical drawbacks in actual injection and migration processes.

[0021] Conventional injection enhancers lack targeted migration control mechanisms. Before reaching their target location in deep reservoirs, they are prone to premature adsorption and ineffective retention in the migration channels and near-wellbore zones, resulting in significant agent loss, low utilization rates, and difficulty in penetrating deep micro- and nano-pores to exert their effects. Furthermore, these systems rely solely on weak physical interactions such as van der Waals forces and electrostatic attraction to bond with the rock surface, resulting in poor interfacial adhesion and weak erosion resistance. Under conditions of high salinity, high temperature, and high-velocity water flow, the agent layer is easily desorbed, detached, and washed away with the water flow, failing to form a stable protective layer on the pore throat surface.

[0022] The aforementioned problems collectively lead to a rapid decline in the injection effect and a sharp rebound in injection pressure in the short term. Not only is it impossible to achieve long-term stable injection, but it may also cause secondary pore and throat blockage due to the agglomeration of nanoparticles after reagent desorption. Ultimately, it is difficult to meet the engineering requirements for long-term mine water reinjection in deep, low-permeability, and highly heterogeneous reservoirs.

[0023] The embodiments of this application will be described in detail below.

[0024] A pH-responsive mine water reinjection enhancer for water-rock interface lubrication, comprising: Hydrophilic inorganic nanoparticles; Coupling agents; A polymer is grafted onto the surface of the hydrophilic inorganic nanoparticles via the coupling agent. The polymer monomers include pH-sensitive monomers containing carboxyl or amino groups and quaternary ammonium salt cationic monomers, so that the polymer chains coil and shrink under acidic or neutral conditions, and stretch and connect to the wall surface to be treated under alkaline conditions.

[0025] In this embodiment, a coupling agent is used to graft the polymer onto the surface of inorganic nanoparticles via chemical bonds. This significantly improves the structural stability of the particles under conditions of high mineralization, high temperature, and high-speed shear, preventing polymer layer detachment and nanoparticle aggregation. The polymer chain simultaneously introduces carboxyl or amino pH-sensitive groups and quaternary ammonium salt cationic groups, synergistically achieving pH-responsive intelligent transport and anchoring: when the additive is in an acidic or neutral environment, the carboxyl groups on the pH-sensitive groups exist in the form of -COOH or protonated -NH3. + In its current form, the charges within the chain segments attract each other, and the molecular chains are tightly coiled. At this point, the hydrated particle size is small, the surface charge density is low, and the overall particle is electrically neutral or weakly charged, possessing excellent deep migration capabilities. It can smoothly pass through the pore throat and reach the treatment wall location in the formation fissure. When the injector reaches the target location, it switches to an alkaline environment, and a large number of carboxyl groups dissociate into negatively charged carboxylate groups, while amino groups lose protons and become neutral. The negative charge within the chain segments increases significantly and exceeds the positive charge of the quaternary ammonium salt, generating a strong electrostatic repulsion force within the chain, allowing the coiled polymer chain segments to fully unfold. At the same time, the quaternary ammonium salt cationic groups can form strong electrostatic adsorption with the negatively charged rock and clay surfaces, allowing the particles to be firmly anchored to the pore throat wall, forming a stable and dense protective layer, thereby achieving the targeted injector effect of "first migration, then fixation".

[0026] In some embodiments, the polymer monomers of the polymer further include anionic monomers containing sulfonic acid groups and acrylamide monomers.

[0027] In this embodiment, introducing anionic monomers containing sulfonic acid groups into the polymer can enhance the polymer chain's resistance to salt and calcium and magnesium ions, improve the dispersion stability of the injection agent in high-salinity mine water, and inhibit salting out and agglomeration. Introducing acrylamide monomers can improve the water solubility, flexibility, and interfacial compatibility of the polymer chain, reduce the adsorption resistance between particles and rock surfaces, and enhance the strength of the hydration film, further improving the wetting reversal and drag reduction effects.

[0028] In some embodiments, the mass ratio of the pH-sensitive monomer containing carboxyl or amino groups, the quaternary ammonium salt cationic monomer, the anionic monomer containing sulfonic acid groups, and the acrylamide monomer is (0.5-1.5):(0.5-1.5):(2-4):(5-7).

[0029] In this embodiment, the formulation achieves optimal synergy between pH responsiveness, cationic adsorption, anionic salt resistance, and hydrophilic stability. A moderate proportion of pH-sensitive monomers ensures sensitive response without affecting migration; a sufficient proportion of quaternary ammonium salt cationic monomers provides cationic sites, resulting in strong electrostatic adsorption with negatively charged rocks / clays for secure anchoring; a reasonable proportion of sulfonic acid monomers significantly enhances the injector's salt and temperature resistance, calcium and magnesium ion resistance, and high-temperature resistance, preventing agglomeration failure in high-salinity mines; and a predominantly acrylamide monomer ensures overall water solubility and structural stability. This formulation results in an injector with excellent migration, adhesion, salt resistance, and long-lasting injector enhancement capabilities.

[0030] In some embodiments, the pH-sensitive monomer containing carboxyl or amino groups includes one or more of acrylic acid, methacrylic acid, itaconic acid, maleic acid, fumaric acid, ethyl aminoacrylate, and methyl aminomethacrylate.

[0031] In this embodiment, pH-sensitive monomers are optimized, as different monomers can impart differentiated response strength, structural stability, and compatibility to the injector. Among them, acrylic acid has high reactivity and high carboxyl density, resulting in sensitive pH response. Under alkaline conditions, it can rapidly dissociate to achieve chain segment extension and charge reversal. Methacrylic acid has methyl groups on its side chains, with moderate steric hindrance, which can improve the hydrolysis resistance and thermal stability of the polymer chain, making it suitable for formation environments with higher temperatures. Itaconic acid, maleic acid, and fumaric acid all contain dicarboxyl structures with more dense carboxyl sites, which can significantly enhance the pH response amplitude and charging capacity, while improving the anchoring strength of particles on the rock surface. Ethyl aminoacrylate and methyl aminomethacrylate contain amino functional groups, which can protonate and become positively charged under acidic conditions. They can synergistically regulate the chain segment coiling state with quaternary ammonium salt cations, and deprotonate and become neutral under alkaline conditions, achieving complementary regulation of charge state and broadening the pH response range of the injector. The monomers mentioned above, whether used alone or in combination, can introduce stable and reliable pH-sensitive sites into the polymer chain, ensuring that the injection enhancer exhibits a contractile transport state in acidic environments and rapidly expands and anchors in alkaline environments, thus meeting the intelligent injection needs of low-permeability reservoirs.

[0032] In some embodiments, the quaternary ammonium salt cationic monomer includes one or more of methacryloyloxyethyltrimethylammonium chloride, acryloyloxyethyltrimethylammonium chloride, dimethyl diallyl ammonium chloride, methacrylamidopropyltrimethylammonium chloride, and vinylbenzyltrimethylammonium chloride.

[0033] In this embodiment, one or more of the following are selected as quaternary ammonium salt cationic monomers: methacryloyloxyethyltrimethylammonium chloride, acryloyloxyethyltrimethylammonium chloride, dimethyl diallyl ammonium chloride, methacrylamidopropyltrimethylammonium chloride, and vinylbenzyltrimethylammonium chloride. Stable and strongly hydrophilic quaternary ammonium cation sites can be introduced into the polymer side chain.

[0034] Among them, methacryloyloxyethyltrimethylammonium chloride and acryloyloxyethyltrimethylammonium chloride exhibit high polymerization activity and high cation density, resulting in strong electrostatic interactions with the negatively charged surfaces of rocks and clays. These significantly enhance particle anchoring strength and erosion resistance. Dimethyl diallyl ammonium chloride demonstrates excellent water solubility and compatibility, exhibiting stable structure after polymerization and resistance to hydrolysis. It maintains charge strength in high-salinity formation water, preventing salting-out failure. Methacrylamide propyltrimethylammonium chloride exhibits outstanding temperature and hydrolysis resistance, making it suitable for high-temperature deep reservoirs and capable of maintaining cation adsorption over a long period. Vinylbenzyltrimethylammonium chloride possesses strong structural rigidity, enhancing polymer chain stability and contributing to improved compactness and durability of the expanded adsorption film. These quaternary ammonium salt monomers, used alone or in combination, participate in chain charge balance and maintain coiled transport under acidic conditions. Under alkaline conditions, they synergistically work with expanded carboxylate anions to strengthen multi-point anchoring between particles and formation walls. Simultaneously, they effectively inhibit clay mineral hydration swelling and particle migration, ensuring long-term stability during injection.

[0035] In some embodiments, the sulfonic acid-containing anionic monomer includes one or more of 2-acrylamido-2-methylpropanesulfonic acid, sodium propylene sulfonate, sodium methpropylene sulfonate, sodium styrene sulfonate, and sodium vinyl sulfonate.

[0036] In this embodiment, one or more of 2-acrylamido-2-methylpropanesulfonic acid, sodium propylene sulfonate, sodium methpropylene sulfonate, sodium styrene sulfonate, and sodium vinyl sulfonate are selected as anionic monomers containing sulfonic acid groups. This can introduce strongly hydrophilic and strongly ionized sulfonate groups into the polymer molecular chain, significantly improving the salt resistance, dispersion stability, and interfacial wettability of the additive in high-salinity, high-calcium-magnesium, and high-temperature formation water environments.

[0037] Among them, 2-acrylamido-2-methylpropanesulfonic acid (AMPS) exhibits outstanding temperature resistance, salt resistance, and hydrolysis resistance, significantly inhibiting particle agglomeration caused by high mineralization while enhancing the hydration and stretching ability of polymer chains. Sodium propylene sulfonate and sodium methpropylene sulfonate possess excellent water solubility and high polymerization activity, rapidly introducing stable negative charges to enhance particle dispersibility during the transport phase and reduce adsorption losses. Sodium styrene sulfonate exhibits strong structural rigidity, improving the density and durability of the polymer film and enhancing its erosion resistance after anchoring. Sodium vinyl sulfonate demonstrates high reactivity and good chain segment flexibility, contributing to improved grafting uniformity between the polymer and inorganic nanoparticles and enhancing the overall system stability. The above sulfonic acid monomers, used alone or in combination, can provide a moderate negative charge to maintain dispersion during the acidic transport phase, synergistically enhance surface negative charge with carboxylate groups during the alkaline anchoring phase, and provide long-term resistance to high-salt environments, ensuring stable transport, firm anchoring, and long-term pressure-reducing injection enhancement of the additive.

[0038] In some embodiments, the acrylamide monomer includes one or more of acrylamide, N-methylacrylamide, N-ethylacrylamide, N-isopropylacrylamide, N,N-dimethylacrylamide, N-hydroxymethylacrylamide, and N-tert-butylacrylamide.

[0039] In this embodiment, one or more of acrylamide, N-methylacrylamide, N-ethylacrylamide, N-isopropylacrylamide, N,N-dimethylacrylamide, N-hydroxymethylacrylamide, and N-tert-butylacrylamide are selected as acrylamide monomers, which can provide excellent water solubility, flexibility, film-forming properties and structural stability for the polymer backbone, and form good synergy with pH-sensitive units, cationic units and sulfonic acid units.

[0040] Acrylamide, with its high water solubility and polymerization activity, significantly enhances the hydrophilicity and hydration capacity of polymer chains, ensuring high dispersion and minimal agglomeration of nanoparticles in mine water. N-methylacrylamide and N-ethylacrylamide, with their short alkyl side chains, improve chain flexibility without affecting charge response, thus enhancing particle spreading and film-forming ability on rock surfaces. N-isopropylacrylamide combines thermosensitive properties with a good hydrophilic-hydrophobic balance, making it suitable for high-temperature formations and improving temperature resistance without weakening pH response behavior. N,N-dimethylacrylamide exhibits moderate steric hindrance and outstanding hydrolysis resistance, improving the structural stability of molecular chains under high mineralization and high-temperature environments, and extending the synergist's shelf life. N-hydroxymethylacrylamide provides additional hydrogen bonding sites, enhancing the bonding strength between nanoparticles and rock walls, and improving the density of the protective film. N-tert-butylacrylamide has significant steric hindrance, inhibiting excessive molecular chain entanglement and improving flowability and migration during injection.

[0041] The above-mentioned acrylamide monomers, used alone or in combination, can effectively adjust the flexibility, water solubility, and adsorption film-forming ability of the molecular chain, enabling the injection enhancer to be stably dispersed and transported under acidic conditions and to quickly form a film and anchor under alkaline conditions, ultimately achieving a stable and long-lasting pressure reduction and injection enhancement effect.

[0042] In some embodiments, the hydrophilic inorganic nanoparticles include one or more of the following: silica nanoparticles, titanium dioxide nanoparticles, alumina nanoparticles, zinc oxide nanoparticles, hydroxyapatite nanoparticles, montmorillonite nanoparticles, and zeolite nanoparticles.

[0043] In this embodiment, one or more of the following hydrophilic inorganic nanoparticles, such as silica, titanium dioxide, alumina, zinc oxide, hydroxyapatite, montmorillonite, and zeolite, are selected as the rigid core. This core provides structural support, size control, chemical stability, and interface compatibility for the additive, ensuring reliable service of the overall material in the geological environment.

[0044] Among them, silica nanoparticles are highly hydrophilic and rich in surface silanol groups, making them readily bonded to coupling agents. They exhibit high grafting efficiency and stable dispersion, making them the preferred core for enhancing injection in low-permeability sandstone reservoirs. Titanium dioxide, alumina, and zinc oxide nanoparticles possess high mechanical strength and outstanding temperature, acid, and alkali resistance, maintaining their morphology intact under high-temperature and complex pH formation conditions, thus avoiding secondary blockage caused by particle breakage. Hydroxyapatite nanoparticles exhibit strong surface polarity and good compatibility with rock minerals, enhancing hydrogen bond adsorption and adhesion strength on formation walls. Montmorillonite and zeolite nanoparticles possess layered or porous structures, increasing the overall specific surface area, improving polymer grafting amount and film uniformity, while simultaneously strengthening the inhibition of clay minerals and pore throat modification effects. These hydrophilic inorganic nanoparticles have controllable particle size, strong chemical stability, and sufficient interfacial activity. They can serve as a supporting framework to resist high temperature, high pressure, and fluid shearing, while also providing stable reaction sites for polymer grafting, synergistically achieving the comprehensive functions of deep transport, fixed-point anchoring, and long-term anti-swelling of the injection enhancer.

[0045] Based on the same inventive concept, this application discloses an injection-enhancing working fluid, comprising the above-mentioned injection enhancer, solution and additives.

[0046] In this embodiment, the injection working fluid uses an aqueous solution as the dispersion medium, which can be directly prepared using mine water, reducing on-site preparation costs and construction difficulty. Adding appropriate additives can further improve the solubility, dispersibility, and interfacial activity of the injection agent, preventing particle agglomeration and extending the effective transport distance. The overall working fluid exhibits stable performance, strong injectability, and good compatibility, and can be directly used for on-site injection construction.

[0047] Based on the same inventive concept, this application discloses a method for increasing mine water injection, comprising: Remove dirt from the wall surface to be treated, wherein the wall surface to be treated is the wall surface of the formation fissure; The pH of the booster working solution is adjusted to acidic to obtain an acidic booster working solution. After the acidic injection fluid is injected into the formation fractures, the pH of the acidic injection fluid is adjusted to alkaline. Mine water is injected into the fissures in the formation.

[0048] In this embodiment, firstly removing surface contaminants opens up pore channels between the near-wellbore and deep wells, preventing impurities from affecting agent adsorption and transport. Injection under acidic conditions allows the additive to remain in a coiled transport state, smoothly reaching the deep target location and reducing premature adsorption loss. Subsequent adjustment to alkaline conditions triggers chain segment expansion and anchoring, ensuring the particles firmly bond to the rock and clay surface, forming a superhydrophilic, erosion-resistant, and expansion-resistant long-lasting protective layer.

[0049] The following examples, comparative examples, and... Figure 1-4 The above embodiments will be described.

[0050] Example 1 The preparation process of pH-responsive mine water reinjection enhancer for water-rock interface lubrication includes: Core modification (introduction of active sites): 10 g of hydrophilic nano-silica (SiO2) with a particle size of 30 nm was dispersed in 200 mL of ethanol / water (volume ratio 9:1) mixed solvent and ultrasonically dispersed for 30 minutes. 0.5 g of silane coupling agent KH-570 (γ-methacryloyloxypropyltrimethoxysilane) was added, the pH was adjusted to 4.0, and the mixture was refluxed at 75 °C for 6 hours. After the reaction was completed, the mixture was centrifuged, washed three times with ethanol, and dried to obtain modified nano-silica with active double bonds on its surface.

[0051] (2) Shell grafting (in-situ free radical polymerization): Disperse 2.0 g of the above modified nano silica in 100 mL of deionized water. Add the following functional monomers to the system in sequence: acrylamide (AM) 3.0 g, 2-acrylamido-2-methylpropanesulfonic acid (AMPS) 1.5 g, acrylic acid (AA) 0.5 g, and cationic monomer methacryloyloxyethyltrimethylammonium chloride (DMC). After purging with nitrogen for 30 minutes to remove oxygen, raise the temperature to 80 °C, add 0.05 g of potassium persulfate (KPS) initiator, and react at a constant temperature for 4 hours to obtain the product. The product is purified by acetone precipitation, dialysis (molecular weight cutoff 3500 Da), and freeze-drying to obtain a white powdery additive.

[0052] The additive comprises: hydrophilic inorganic nanoparticles; a coupling agent; and a polymer, wherein the polymer is grafted onto the surface of the hydrophilic inorganic nanoparticles via the coupling agent. The polymer is polymerized from a carboxyl-containing pH-sensitive monomer (acrylic acid), a quaternary ammonium salt cationic monomer (methacryloyloxyethyltrimethylammonium chloride), a sulfonic acid-containing anionic monomer (2-acrylamido-2-methylpropanesulfonic acid), and an acrylamide monomer (acrylamide).

[0053] Characterization results of the above-mentioned filler agent: thermogravimetric analysis (TGA) showed that the polymer grafting rate was 88.5%; isoelectric point test showed that its pI value was 5.8.

[0054] Example 2 The difference between Example 2 and Example 1 is that acrylamide is replaced with N-isopropylacrylamide (NIPAM), while the other steps are the same as in Example 1. Experiments have shown that the injection enhancer prepared in Example 2 is more suitable for reinjection scenarios with water temperatures >60℃.

[0055] Example 3 (1) Formula for supplementing working fluid: Solution: Simulated mine water from the Liujiagou Formation (total mineralization 30000 mg / L, Ca...) 2+ +Mg 2+ (Content 1200mg / L) Injection agent: The injection enhancer prepared in Example 1, concentration 0.15 wt%; Additive: Isopropanol (cosolvent), concentration 0.3wt%.

[0056] (2) Methods for increasing mine water injection An indoor simulation experiment was conducted using a natural sandstone core with a permeability of 2.5 mD and a length of 10 cm. The specific steps are as follows: S1. Pretreatment: Inject citric acid descaling solution with a mass fraction of 1% and a pore volume of 2 times into the core to remove inorganic scale adhering to the pore throat and crevice surface of the core, and to unclog the water injection channels, so as to provide a clean interface for subsequent reagent transport and adsorption.

[0057] S2. Main Slug Injection (Deep Migration): Inject a booster working solution (from Example 3) with a pH adjusted to 5.5-6.0 at a constant flow rate of 0.5 mL / min, with an injection volume of 5 times the pore volume (PV). Under these acidic conditions, the polymer chains on the surface of the booster particles are in a coiled and contracted state, with an average hydrated particle size of 45 nm. The particles are stably dispersed, with low interfacial resistance, and can smoothly enter deep micro- and nano-pores, achieving effective migration. The injection pressure shows a steady downward trend.

[0058] S3. Immobilization and Activation Slug (Smart Anchoring): Continue injecting a weakly alkaline buffer solution of sodium carbonate and sodium bicarbonate at a pH of 9.5, equal to 1 pore volume (PV). The alkaline environment triggers rapid dissociation of carboxyl groups on the surface of the injector, causing polymer chains to transition from a coiled state to a fully extended state and form a strong electrostatic interaction with the core surface, achieving targeted anchoring and adsorption.

[0059] S4. Normal reinjection and long-term scouring: Stop injecting chemical agents and switch to continuous water drive with simulated mine water. The injection volume reaches 50 times the pore volume (PV). Record the changes in water injection pressure throughout the process and evaluate the scouring resistance and long-term stability of the injection system.

[0060] Comparative Example 1 The difference between Comparative Example 1 and Example 3 is that the additive used in Comparative Example 1 did not undergo the silane coupling agent grafting step, while the remaining steps were the same as in Example 3.

[0061] Comparative Example 2 The difference between Comparative Example 2 and Example 3 is that step S3 was not performed, while the remaining steps are the same as in Example 3.

[0062] Comparative Example 3 The difference between Comparative Example 3 and Example 3 is that no injection enhancer was used. Instead, after step S1, a soil acid solution with a mass fraction of 12% HCl + 3% HF was injected into the core, and then step S4 was performed.

[0063] Performance Analysis: (1) Long-term reinjection pressure change test (see instruction manual appendix) Figure 1 ) Using the initial core injection pressure as a 100% baseline, the changes in injection pressure during the simulated continuous mine water flushing process in the S4 stage of Example 3 and Comparative Examples 1-3 were recorded to evaluate the injection stability and scour resistance of each system.

[0064] Example 3 (Invention): After continuous flushing to 50 PV, the injection pressure can be stably maintained at about 60% of the initial pressure, with a pressure rebound of less than 5%, and the overall operation is stable. This indicates that after pH-triggered fixation, the nano-protective layer formed by the nanoparticles on the surface of the rock pore throat is firmly anchored and has extremely strong erosion resistance. It will not be lost with long-term water drive and can continuously play the role of clay in preventing swelling and reducing flow resistance, achieving long-term stable pressure reduction and injection.

[0065] Comparative Example 1 (physical compound): When flushed to 10 PV, the injection pressure began to rebound rapidly; when flushed to 30 PV, the pressure had risen back to 95% of the initial pressure, and the injection enhancement effect was basically lost. This is because the polymer and nanoparticles did not form chemical bonds, and the polymer and nanoparticles were easy to desorb and separate, resulting in the agglomeration of nanoparticles and the rapid failure of the anti-swelling function.

[0066] Comparative Example 2 (without activation step): The injection pressure exhibited obvious sawtooth fluctuations, failing to form a stable low-pressure channel, and eventually the pressure rose back to 85% of the initial value. This indicates that without the alkaline activation step, the pH response mechanism cannot be activated, the polymer chains cannot fully extend and anchor, and the nanoparticles exist in a free state, easily carried and transported by the water flow, making it difficult to form a stable protective layer on the pore throat surface.

[0067] Comparative Example 3: Initially, the injection pressure dropped sharply due to the dissolving effect of the acid on the rock skeleton; however, after continuous flushing to 20 PV, the pressure rapidly increased and exceeded the initial pressure, reaching 120%. This is because the strong acid destroyed the integrity of the rock structure, causing a large amount of hydration, dispersion and migration of clay minerals, resulting in severe blockage of pore throats and a significant reduction in permeability.

[0068] (2) Wettability contact angle test The original surface of the core showed a water phase contact angle of 32°, indicating weak hydrophilicity and high water flow resistance.

[0069] After treatment according to Example 3 (the present invention), as follows Figure 2 As shown in (a), the contact angle of the water phase on the core surface drops to 0°, and the droplets can spread completely on the surface instantly, exhibiting a super-hydrophilic state, which greatly reduces the frictional resistance of water flow and improves the reinjection efficiency.

[0070] After treatment with Comparative Example 1 and long-term scouring, the contact angle of the core surface recovered to 25°, and the hydrophilic modification effect was significantly reduced, indicating that a large amount of the surface modification layer had fallen off and could not maintain a long-term wetting modification effect.

[0071] like Figure 2 As shown in (b), after treatment with the injection enhancer of the present invention, the scanning electron microscope (SEM) results of the core pore throat surface directly reveal the excellent reservoir protection and long-term injection enhancement micro-mechanism: the clay minerals on the pore throat surface are completely covered by a uniform and dense nano-adsorption film. The film is composed of ordered stacking of nanoparticles, which are closely attached to the surface of the rock and clay skeleton, forming a stable physical isolation barrier; at the same time, the pore throat channels remain unobstructed, and no obvious particle agglomeration or pore throat blockage is observed, confirming that the system of the present invention will not cause secondary damage to the reservoir. The above experimental results fully demonstrate that: Figure 3 As shown, the additive in this invention exhibits excellent tolerance and long-term stability by grafting polymers onto nanoparticles (a "core-shell" chemical grafting structure). Figure 3 (a) This structurally solves the problem of surfactants and polymers (physical compound structure). Figure 3(b) The industry problem of easy desorption and detachment under high mineralization, high temperature and high flow rate scouring conditions. Experiments show that under continuous shearing for 2 hours at a high mineralization of 30000 mg / L and 45℃, the particle size change rate of the nanoparticles of the present invention is less than 5%, and the dispersion state remains stable, while the conventional physical compound system has shown serious agglomeration failure.

[0072] like Figure 4 As shown, this invention achieves precise and intelligent fixation through a pH-responsive core-shell structure, extending the effective period of the injection by more than 3 times: during the acidic or neutral migration stage ( Figure 4 (a) pH 5.0–6.5, pH less than 6.0 is suitable for pH-sensitive monomers containing carboxyl groups, pH 6.0–6.5 is suitable for pH-sensitive monomers containing amino groups), the polymer chain segments exhibit a "coil-and-contract" conformation, the nanoparticles have small hydrated particle size and low surface charge density, and can smoothly pass through narrow pore throats to migrate to deeper formations, avoiding premature adsorption and loss in the near-wellbore area; upon reaching the target location, it switches to an alkaline environment ( Figure 4 (b) At pH 8.5–10.0, the carboxyl groups rapidly dissociate into carboxylate anions, the polymer chains fully expand from their coiled state, and the zeta potential on the particle surface reverses. Through multi-point electrostatic adsorption and hydrogen bonding, the polymer "grabs" and anchors itself to the surface of rocks and clay minerals, forming a stable and dense nano-protective layer. This intelligent mechanism of "first transport, then fixation" fundamentally solves the industry pain points of conventional nanofluids being easily lost with water flow and unable to establish a long-term anti-swelling layer in deep reservoirs. Field simulation experiments show that the effective period of reinjection after a single treatment can reach more than 30 days, with the water pressure recovery rate less than 10%, far superior to the effective period of only 7–10 days for conventional technologies, providing a reliable guarantee for the long-term stable reinjection of mine water.

[0073] Meanwhile, the present invention has the ability to prevent swelling without damage and reduce drag with high efficiency. The nano-protective layer formed on the surface of the pore throat has super-hydrophilic properties, and the water phase contact angle can be reduced to 0°. It can block the contact between water and clay minerals like an isolation membrane, inhibit the hydration and swelling of clay, and has a swelling prevention rate of more than 90%. It also significantly reduces the water flow resistance in the micropores and significantly reduces the recharge start-up pressure.

[0074] The above experimental results fully demonstrate that the core-shell chemical grafting structure and pH-responsive intelligent fixation process adopted in this invention work synergistically to fundamentally solve common problems in deep mine water reinjection, such as easy detachment and failure of chemical agents, short effective period, and easy damage to reservoirs. It is significantly superior to existing technologies in terms of stability, long-term effectiveness, pressure reduction and injection enhancement effect, and reservoir protection, and has outstanding technical advantages and unexpected technical effects.

[0075] Those skilled in the art should understand that the discussion of any of the above embodiments is merely exemplary and is not intended to imply that the scope of this application is limited to these examples; under the concept of this application, the technical features of the above embodiments or different embodiments can also be combined, the steps can be implemented in any order, and there are many other variations of different aspects of the embodiments of this application as described above, which are not provided in detail for the sake of brevity.

[0076] Although this application has been described in conjunction with specific embodiments thereof, many substitutions, modifications, and variations of these embodiments will be apparent to those skilled in the art from the foregoing description. The embodiments of this application are intended to cover all such substitutions, modifications, and variations falling within the broad scope of the claims of this application. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the embodiments of this application should be included within the protection scope of this application.

Claims

1. A pH-responsive mine water reinjection enhancer for water-rock interface lubrication, characterized in that, include: Hydrophilic inorganic nanoparticles; Coupling agents; A polymer is grafted onto the surface of the hydrophilic inorganic nanoparticles via the coupling agent. The polymer monomers include pH-sensitive monomers containing carboxyl or amino groups and quaternary ammonium salt cationic monomers, so that the polymer chains coil and shrink under acidic or neutral conditions, and stretch and connect to the wall surface to be treated under alkaline conditions.

2. The injection enhancer according to claim 1, characterized in that, The polymer monomers also include anionic monomers containing sulfonic acid groups and acrylamide monomers.

3. The injection enhancer according to claim 2, characterized in that, The mass ratio of the pH-sensitive monomer containing carboxyl or amino groups, the quaternary ammonium salt cationic monomer, the anionic monomer containing sulfonic acid groups, and the acrylamide monomer is (0.5-1.5):(0.5-1.5):(2-4):(5-7).

4. The injection enhancer according to claim 1, characterized in that, The pH-sensitive monomer containing carboxyl or amino groups includes one or more of acrylic acid, methacrylic acid, itaconic acid, maleic acid, fumaric acid, ethyl aminoacrylate, and methyl aminomethacrylate.

5. The injection enhancer according to claim 1, characterized in that, The quaternary ammonium salt cationic monomers include one or more of methacryloyloxyethyltrimethylammonium chloride, acryloyloxyethyltrimethylammonium chloride, dimethyl diallyl ammonium chloride, methacrylamidopropyltrimethylammonium chloride, and vinylbenzyltrimethylammonium chloride.

6. The injection enhancer according to claim 2, characterized in that, The sulfonic acid-containing anionic monomer includes one or more of 2-acrylamido-2-methylpropanesulfonic acid, sodium propylene sulfonate, sodium methpropylene sulfonate, sodium styrene sulfonate, and sodium vinyl sulfonate.

7. The injection enhancer according to claim 2, characterized in that, The acrylamide monomer includes one or more of acrylamide, N-methylacrylamide, N-ethylacrylamide, N-isopropylacrylamide, N,N-dimethylacrylamide, N-hydroxymethylacrylamide, and N-tert-butylacrylamide.

8. The injection enhancer according to claim 1, characterized in that, The hydrophilic inorganic nanoparticles include one or more of the following: silica nanoparticles, titanium dioxide nanoparticles, alumina nanoparticles, zinc oxide nanoparticles, hydroxyapatite nanoparticles, montmorillonite nanoparticles, and zeolite nanoparticles.

9. A working fluid for increasing fluid volume, characterized in that, Includes the injecting agent, solution, and additives as described in any one of claims 1-8.

10. A method for reinjecting and increasing mine water, characterized in that, include: Remove dirt from the wall surface to be treated, wherein the wall surface to be treated is the wall surface of the formation fissure; The pH of the booster working solution is adjusted to acidic to obtain an acidic booster working solution. After the acidic injection fluid is injected into the formation fractures, the pH of the acidic injection fluid is adjusted to alkaline. Mine water is injected into the fissures in the formation.

Images