Modified nanoparticle and preparation method therefor, sand consolidation material and use thereof, and sand consolidation method for oil / gas well

Abstract

The present invention relates to the technical field of sand consolidation in oil / gas wells, and in particular to a modified nano-particle and a preparation method therefor, a sand consolidation material and a use thereof, and a sand consolidation method for an oil / gas well. The modified nanoparticle comprises an inorganic nanoparticle, coupling groups grafted on the surface of the inorganic nanoparticle, and crosslinking reactive groups and hydrophilic groups grafted on the coupling groups. The use of the modified nanoparticle in the present invention to prepare a sand consolidation material can significantly improve the sand consolidation effect of the sand consolidation material.

Description

Modified nanoparticles and preparation method thereof, sand consolidation material and application thereof, and oil and gas well sand consolidation method

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of Chinese patent application 202311745341.7 filed on December 18, 2023, the contents of which are incorporated herein by reference. Technical Field

[0003] The present invention relates to oil and gas well sand consolidation (ie sand control) technology, and in particular to a modified nanoparticle and a preparation method thereof, a sand consolidation material and an application thereof, and an oil and gas well sand consolidation method. Background Art

[0004] Unconsolidated sandstone reservoirs are widely distributed worldwide, possess abundant reserves, and play a crucial role in the oil and gas extraction industry. Sand production is a major challenge in the development of these reservoirs and a major cause of problems such as sand burial, wellbore blockage, pump sticking, and frequent maintenance. Therefore, most wells in unconsolidated sandstone reservoirs require sand control measures to ensure normal production.

[0005] Running sand screens downhole is the most common sand control measure in the oil and gas industry. Essentially, it involves constructing a filtration system downhole to prevent formation sand from entering the wellbore. This sand control measure does not fundamentally address the sand production problem. Formation sand accumulates along with the fluid on the outside of the screen, causing blockage and reduced oil and gas well production. Furthermore, in specialized well conditions such as small boreholes, long well sections, casing-to-convert wells, and separate injection and production wells, running and subsequent recovery of the screens is extremely difficult, creating a significant risk of operational failure.

[0006] The fundamental cause of formation sand production is the detachment of sand particles from the rock matrix and their subsequent extraction with fluids. Theoretically, chemical sand consolidation can be used to bind the loose sand particles, preventing sand production and fundamentally resolving the problem. Furthermore, chemical sand consolidation offers advantages such as a simple construction process, the elimination of a wellbore string, and low cost, offering significant technical advantages in specialized well conditions.

[0007] At present, chemical sand consolidation technology mainly includes three technical routes: (1) modified resins, which are prepared into sand consolidating agents through chemical modification based on resin materials, but the problem of reservoir damage has not been effectively solved; (2) oligomers, which use various small molecular polymers to achieve sand control through electrostatic adsorption. Due to their very low bonding strength, they can usually only be used as an auxiliary means of mechanical sand control; (3) nanomaterials, which use inorganic nanosilicates to solidify on the surface of sand particles to form a hard gel to consolidate the sand particles together. It is still in the laboratory research stage and has not been applied on a large scale. Its consolidation strength and permeability retention still have a lot of room for improvement. Overall, due to the problems of low consolidation strength and large permeability damage, the existing chemical sand consolidation technology has the disadvantages of short effective period of sand control and large impact on production in actual application, which limits its application scale.

[0008] Summary of the Invention

[0009] The present invention aims to overcome the problems of existing chemical sand consolidation technologies, such as significant reservoir damage, low consolidation strength, short effective period, and inapplicability in fine silt oil reservoirs, by providing modified nanoparticles and their preparation methods, sand consolidation materials and their applications, and a method for sand consolidation in oil and gas wells. When applied to oil and gas wells, the modified nanoparticles of the present invention have the advantages of high sand consolidation strength, minimal permeability damage, a long effective period, safety, and environmental protection. They also cause minimal damage to the reservoir, enhance the mechanical properties of formation rock, improve the sealing effect, and extend the effective period of sand consolidation, resulting in a better sand consolidation effect and a wide range of applications.

[0010] In order to achieve the above-mentioned object, the first aspect of the present invention provides a modified nanoparticle, wherein the modified nanoparticle comprises an inorganic nanoparticle, a coupling group grafted on the surface of the inorganic nanoparticle, and a cross-linking reaction group and a hydrophilic group grafted on the coupling group.

[0011] The second aspect of the present invention provides a method for preparing the modified nanoparticles according to the first aspect of the present invention, wherein the method comprises the following steps:

[0012] (a) mixing inorganic nanoparticles, a coupling agent, and a dispersing solvent to obtain a dispersion;

[0013] (b) mixing the cross-linking organic matter, the hydrophilic organic matter and the diluent to obtain a modified treatment solution;

[0014] (c) contacting the dispersion, the modified treatment solution, and a catalyst to perform a grafting reaction to obtain a grafting reaction solution;

[0015] (d) first adding a pH adjuster to the grafting reaction solution to obtain a neutral grafting reaction solution, and then separating the neutral grafting reaction solution to obtain modified nanoparticles.

[0016] The third aspect of the present invention provides a sand-consolidating material, wherein, by weight, the raw materials for preparing the sand-consolidating material include the modified nanoparticles described in the first aspect of the present invention, an aqueous curing agent, an anti-swelling agent and a solvent, wherein the solid content of the sand-consolidating material is 10-50wt%, and the mass ratio of the modified nanoparticles, the aqueous curing agent and the anti-swelling agent is 100:5-20:1-6.

[0017] A fourth aspect of the present invention provides an application of the sand consolidation material described in the third aspect of the present invention in oil and gas sand consolidation.

[0018] A fifth aspect of the present invention provides a method for sand consolidation in oil and gas wells, wherein the method comprises:

[0019] Step 1, injecting nitrogen foam into the oil layer to clean the wellbore;

[0020] Step II, injecting a chemical profile control temporary plugging agent into the oil layer to perform preliminary plugging of the oil layer;

[0021] Step III: first inject the sand consolidation material described in the third aspect of the present invention into the oil layer, and then inject the displacement fluid for displacement.

[0022] Through the above technical solution, the beneficial technical effects achieved by the present invention are as follows:

[0023] 1) The modified nanoparticles provided in the present invention use inorganic nanoparticles as their cores. Using grafting modification technology, cross-linking reaction groups are introduced onto the surface of the inorganic nanoparticles, increasing the reactivity of the inorganic nanoparticles. Under the influence of formation temperature, these nanoparticles can undergo a cross-linking and curing reaction with a water-based curing agent to form a high-strength polymer material, thereby significantly improving the consolidation strength of formation sand.

[0024] 2) The modified nanoparticles provided in the present invention use inorganic nanoparticles as their core and adopt grafting modification technology to introduce hydrophilic groups, thereby increasing the zeta potential and water solubility of the inorganic nanoparticles, thereby significantly increasing the dispersibility and water solubility of the inorganic nanoparticles in aqueous solution, and significantly reducing damage to the reservoir;

[0025] 3) After the sand consolidation material provided by the present invention is injected into the oil reservoir, the modified nanoparticles in the sand consolidation material automatically adsorb on the surface of the formation sand and, under the influence of the formation temperature, chemically react with the curing agent to generate a network of high molecular polymers, forming a high-strength hard film on the surface of the formation sand, cementing the loose sand particles, thereby significantly improving the sand consolidation effect;

[0026] 4) The anti-swelling agent in the sand consolidation material provided by the present invention can occupy most of the rock pores, prevent pore blockage, and inhibit the expansion of clay minerals, thereby further reducing reservoir damage;

[0027] 5) The consolidated core prepared by the sand consolidation material provided in the present invention has a relatively high strength and still has good permeability in fine silt sand, and can be used in fine silt sand oil layers. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] FIG1 is a schematic structural diagram of modified nanoparticles provided in the present invention;

[0029] FIG2 is a schematic diagram of the sand consolidation principle of the sand consolidation material provided by the present invention;

[0030] FIG3 is an infrared spectrum of the modified nanoparticles prepared in Example 1 of preparing modified nanoparticles;

[0031] FIG4 is a SEM image of a consolidated core prepared using the sand consolidation material in Example 1;

[0032] FIG5 is a SEM image of a consolidated core prepared using the phenolic resin sand consolidating agent in Comparative Example 1. DETAILED DESCRIPTION

[0033] The endpoints of the ranges disclosed herein and any values ​​are not limited to the exact ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoints of each range, the endpoints of each range and individual point values, and the individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed in this article.

[0034] A first aspect of the present invention provides a modified nanoparticle, wherein the modified nanoparticle comprises an inorganic nanoparticle, a coupling group grafted onto the surface of the inorganic nanoparticle, and a cross-linking reaction group and a hydrophilic group grafted onto the coupling group.

[0035] Wherein, in the present invention, cross-linking reaction group and hydrophilic group are grafted (also promptly be connected) on the surface of inorganic nano particle respectively through coupling group, and the structure of modified nano particle is as shown in Figure 1.Coupling group utilizes chemical bond adsorption on the inorganic nano particle surface, makes inorganic nano particle can combine with the organic matter that contains cross-linking group and the organic matter that contains hydrophilic group.The cross-linking reaction group introduced by coupling group can make inorganic nano particle have cross-linking reaction characteristic, can react chemically with aqueous curing agent, form cross-linked body type structure, thereby inorganic nano particle is connected, obtain high strength solidified layer.The hydrophilic group introduced by coupling group section can make inorganic nano particle can disperse better in aqueous solution, avoid agglomeration.

[0036] In a preferred embodiment of the present invention, based on the weight of the inorganic nanoparticles, the content of the coupling group is 0.1-2.3wt%, preferably 0.9-1.7wt%; the content of the cross-linking reaction group is 16-57wt%, preferably 26-46wt%; and the content of the hydrophilic group is 4-30wt%, preferably 14-24wt%.

[0037] Among them, in the present invention, taking the content of coupling groups as an example, the content of coupling groups is equal to the weight of coupling groups divided by the weight of inorganic nanoparticles. When the content of cross-linking reaction groups is less than 16wt%, it will affect the bonding strength; when the content of cross-linking reaction groups is greater than 57wt%, it will affect the dispersibility of the modified nanoparticles. When the content of hydrophilic groups is less than 4wt%, it will affect the dispersibility of the modified nanoparticles; when the content of hydrophilic groups is greater than 30wt%, it will affect the bonding strength. In other words, the content of cross-linking reaction groups and water-soluble groups in the modified nanoparticles in the present invention must be maintained in a reasonable ratio range in order to have both good bonding strength and dispersion properties.

[0038] In a preferred embodiment of the present invention, the inorganic nanoparticles are selected from one or more of nano-silicon dioxide, nano-carbon fibers, carbon nanotubes, nano-titanium oxide, and nano-aluminum oxide, preferably nano-silicon dioxide.

[0039] Among them, in the present invention, when the inorganic nanoparticles are selected from multiple types (for example, two, three, four or five types) of nano-silicon dioxide, nano-carbon fibers, carbon nanotubes, nano-titanium oxide, and nano-aluminum oxide, the mixing ratio of the various inorganic nanoparticles can be any value, and the present invention does not impose any special limitation on it.

[0040] In a preferred embodiment of the present invention, the coupling groups are derived from a coupling agent, more preferably a silane coupling agent. In the present invention, the siloxane groups derived from the silane coupling agent can further enhance the adhesion between the cross-linking reaction groups and the hydrophilic groups and the inorganic nanoparticles, thereby improving the sand consolidation effect.

[0041] In a preferred embodiment of the present invention, the silane coupling agent is selected from one or more of 3-aminopropyltriethoxysilane (KH550), methyltriethoxysiloxane, γ-(2,3-epoxypropoxy)propyltrimethoxysilane, vinyltrimethylsilane, and vinyltriethoxysilane, preferably 3-aminopropyltriethoxysilane.

[0042] In a preferred embodiment of the present invention, the cross-linking reaction group is derived from a cross-linking organic compound containing an alkenyl group and an epoxy group.

[0043] Among them, in the present invention, the alkenyl group is used to react with the coupling group, thereby grafting the cross-linking reaction group onto the inorganic nanoparticles, and the epoxy group is used to chemically react with the water-based curing agent when used, thereby significantly improving the sand consolidation effect.

[0044] In a preferred embodiment of the present invention, the cross-linked organic matter is selected from small molecule cross-linked organic matter (for example, molecular weight ≤500 g / mol) and / or cross-linked polymers; wherein the small molecule cross-linked organic matter is selected from one or more of 4-vinyl cyclohexane oxide, (R)-2-vinyl oxirane, (S)-2-(but-3-enyl)oxirane, and the cross-linked polymer is selected from one or more of allyl polyoxyalkyl epoxy ether, allyl polyoxyethylene ether epoxy ether, and allyl polyoxyethylene polyoxypropylene epoxy ether.

[0045] Among them, in the present invention, the inventors have found through research that, compared with cross-linked polymers, when small molecule cross-linked organic matter is used to introduce cross-linking reaction groups, not only can the bonding strength of the modified nanoparticles be significantly improved, but the dispersibility of the modified nanoparticles can also be greatly improved, so that the sand-fixing strength and flowability of the sand-fixing material prepared using modified nanoparticles are better, and the damage to the reservoir permeability is less.

[0046] In a preferred embodiment of the present invention, the hydrophilic group is derived from a hydrophilic organic compound containing a hydrophilic group; wherein the hydrophilic group is selected from at least one of a hydroxyl group, an ether group, a carboxyl group, and a sulfonic acid group.

[0047] In a preferred embodiment of the present invention, the hydrophilic organic matter is selected from small molecule hydrophilic organic matter (for example, molecular weight ≤500g / mol) and / or hydrophilic polymer; wherein the small molecule hydrophilic organic matter is selected from one or more of acrylic acid-(methyl)acrylate, 3,4-dihydroxyphenylacrylic acid, 4-hydroxybenzenesulfonic acid, 2-hydroxybenzenesulfonic acid, 3-hydroxybenzenesulfonic acid, 5-hydroxy-1,3-benzenedisulfonic acid, and 2,4-dihydroxybenzenesulfonic acid, and the hydrophilic polymer is selected from one or more of polyethylene glycol monostearate, polyether nonionic surfactant, and isomeric alcohol polyoxyethylene ether.

[0048] In the present invention, polyethylene glycol monostearate, polyether nonionic surfactant, and isomeric alcohol polyoxyethylene ether are all conventional commercially available products and are not particularly limited thereto. The inventors of the present invention have discovered that, compared to small molecule hydrophilic organic compounds, the water solubility and dispersibility of the modified nanoparticles are improved when hydrophilic groups are introduced using hydrophilic polymers.

[0049] In a preferred embodiment of the present invention, in order to avoid clogging of voids during oil and gas production and to improve the rigidity of the sand consolidation bonding layer and the permeability of the rock, preferably, the average particle size of the modified nanoparticles is ≤100 nm, preferably 30-100 nm.

[0050] The second aspect of the present invention provides a method for preparing the modified nanoparticles according to the first aspect of the present invention, wherein the method comprises the following steps:

[0051] (a) mixing inorganic nanoparticles, a coupling agent, and a dispersing solvent to obtain a dispersion;

[0052] (b) mixing the cross-linking organic matter, the hydrophilic organic matter and the diluent to obtain a modified treatment solution;

[0053] (c) contacting the dispersion, the modified treatment solution, and a catalyst to perform a grafting reaction to obtain a grafting reaction solution;

[0054] (d) first adding a pH adjuster to the grafting reaction solution to obtain a neutral grafting reaction solution, and then separating the neutral grafting reaction solution to obtain modified nanoparticles.

[0055] In step (a):

[0056] In a preferred embodiment of the present invention, the dispersing solvent is selected from alcohol solvents, preferably one or more selected from methanol, ethanol, glycerol, triethylene glycol, isopropanol, preferably glycerol.

[0057] In a preferred embodiment of the present invention, 100 parts by weight of inorganic nanoparticles, 0.5-2.5 parts, preferably 1-2 parts, of coupling agent and 200-400 parts, preferably 250-350 parts of dispersing solvent are mixed to obtain an inorganic nanoparticle dispersion.

[0058] In a preferred embodiment of the present invention, the dispersion is mixed at a stirring speed of 6,000-20,000 rpm and a stirring time of 5-20 minutes. In the present invention, mixing the inorganic nanoparticles, coupling agent, and dispersing solvent at the aforementioned stirring speeds can prevent agglomeration and effectively improve the dispersion of the inorganic nanoparticles.

[0059] In step (b):

[0060] In a preferred embodiment of the present invention, the diluent is selected from one or more of ethylene glycol monobutyl ether, diethylene glycol, diethylene glycol butyl ether, ethyl acetate, and benzyl alcohol, preferably ethylene glycol monobutyl ether.

[0061] In a preferred embodiment of the present invention, 20-60 parts, preferably 30-50 parts, of a cross-linking organic matter, 5-35 parts, preferably 15-25 parts, of a hydrophilic organic matter, and 10-40 parts, preferably 20-30 parts, of a diluent are mixed by weight to obtain a modified treatment solution.

[0062] In step (c):

[0063] In a preferred embodiment of the present invention, the catalyst is selected from one or more of azobisisobutyronitrile, cerium oxide, and sodium caprolactam, preferably azobisisobutyronitrile.

[0064] In a preferred embodiment of the present invention, the added amount of the catalyst is 0.1-0.2 parts by weight, preferably 0.12-0.18 parts by weight, based on 100 parts by weight of the inorganic nanoparticles.

[0065] In the present invention, the amounts of inorganic nanoparticles, coupling agent, dispersing solvent, cross-linking organic matter, hydrophilic organic matter, diluent and catalyst involved in the preparation method of modified nanoparticles are all based on 100 parts of inorganic nanoparticles.

[0066] In a preferred embodiment of the present invention, the contacting operation conditions include: firstly adding the modified treatment liquid dropwise to the dispersion, and then adding the catalyst; wherein the adding is carried out at 60-100°C, preferably 70-90°C.

[0067] In a preferred embodiment of the present invention, the operating conditions of the grafting reaction include: reaction temperature of 120-180° C., preferably 140-160° C.; reaction time of 1-6 h, preferably 2-4 h.

[0068] In step (d):

[0069] In a preferred embodiment of the present invention, the pH regulator is selected from one or more of sodium bicarbonate aqueous solution, sodium carbonate solution, potassium bicarbonate aqueous solution, potassium carbonate solution, and ammonia water, preferably sodium bicarbonate aqueous solution.

[0070] In a preferred embodiment of the present invention, the pH value of the neutral grafting reaction solution is 7-8, preferably 7-7.5. In the present invention, the pH adjuster can enhance the stability of the modified nanoparticles and prevent the crosslinking reaction groups and hydrophilic groups on the modified nanoparticles from deteriorating in acidic or alkaline environments after being exposed to moisture.

[0071] In a preferred embodiment of the present invention, the present invention does not impose any particular limitation on separation, and preferably may include filtration and drying.

[0072] In the present invention, the modified nanoparticles are reactive and can be used in sand consolidation for oil and gas wells. For ease of operation, the separation operation can be omitted and the neutral grafting reaction liquid can be directly used in sand consolidation for oil and gas wells.

[0073] The third aspect of the present invention provides a sand-consolidating material, wherein, by weight, the raw materials for preparing the sand-consolidating material include the modified nanoparticles described in the first aspect of the present invention, an aqueous curing agent, an anti-swelling agent and a solvent, wherein the solid content of the sand-consolidating material is 10-50wt%, and the mass ratio of the modified nanoparticles, the aqueous curing agent and the anti-swelling agent is 100:5-20:1-6.

[0074] In the present invention, the modified nanoparticles contain hydrophilic groups, allowing them to be evenly dispersed in the sand-fixing material. When the sand-fixing material is injected into the oil reservoir of an oil and gas well, the modified nanoparticles automatically adsorb on the surface of the formation sand. Under the influence of the formation temperature, the cross-linking reaction groups on the modified nanoparticles react chemically with the aqueous sand-fixing agent to generate a network of high-molecular-weight polymers, which form a high-strength hard film on the surface of the formation sand, thereby cementing the loose sand grains, as shown in Figure 2. The anti-swelling agent can inhibit the expansion and dispersion of clay minerals, significantly reducing damage to the reservoir. It can also prevent the modified nanoparticles from adsorbing on the surface of the clay mineral particles, thereby increasing the adsorption capacity of the modified nanoparticles on the surface of the formation sand.

[0075] In a preferred embodiment of the present invention, the sand-consolidating material has a solid content of 25-35% by weight, and the mass ratio of the modified nanoparticles, the aqueous curing agent, and the anti-swelling agent is 100:8-12:2-4. In the present invention, when the contents of the various components in the sand-consolidating material are within the above-defined ranges, the sand-consolidating material exhibits a more effective sand-consolidating effect.

[0076] In a preferred embodiment of the present invention, the waterborne curing agent is selected from one or more of ZW-6112 waterborne epoxy curing agent, DP-03 waterborne epoxy curing agent, CYDHD-220 waterborne epoxy curing agent, SAC8325 waterborne epoxy curing agent, polyetheramine D230 curing agent, polyetheramine ZD123 curing agent, imidazole, and dimethylimidazole, preferably polyetheramine ZD123 curing agent and / or dimethylimidazole. In the present invention, the waterborne epoxy curing agent can be a commercially available product or prepared by an existing method, and the present invention does not specifically limit it.

[0077] In a preferred embodiment of the present invention, the anti-swelling agent is selected from one or more of inorganic salt anti-swelling agents, organic quaternary ammonium salt anti-swelling agents, and organic cationic polymer anti-swelling agents.

[0078] In the present invention, the anti-swelling agent is not particularly limited. Conventional inorganic salt anti-swelling agents in the art (e.g., potassium chloride, sodium chloride, potassium carbonate, ammonium chloride), organic quaternary ammonium salt anti-swelling agents (e.g., polyhydroxypropyl dimethyl ammonium chloride) and organic cationic polymer anti-swelling agents (e.g., organic cationic polymer anti-swelling agents) can all be used in the present invention.

[0079] In a preferred embodiment of the present invention, the solvent is not particularly limited and may be water or the dispersing solvent and / or diluent described in the second aspect of the present invention. In the present invention, to promote the dispersion of the aqueous curing agent and anti-swelling agent in the solvent, the aqueous curing agent and anti-swelling agent may be separately prepared into dispersions using a portion of water before mixing.

[0080] In a preferred embodiment of the present invention, the method for preparing the sand consolidation material comprises the following steps:

[0081] (1) preparing modified nanoparticles and / or neutral grafting reaction solution;

[0082] (2) The modified nanoparticles and / or neutral grafting reaction liquid, the aqueous curing agent, the anti-swelling agent and the solvent are uniformly mixed to obtain a sand consolidation material.

[0083] Preferably, in the present invention, the liquid in the neutral grafting reaction solution has good compatibility with the solvent used to prepare the sand-consolidating material. To simplify the process, the sand-consolidating material can be prepared directly from the neutral grafting reaction solution without separating the modified nanoparticles. When the sand-consolidating material is prepared using the neutral grafting reaction solution, the concentration of the neutral grafting reaction solution can be adjusted accordingly, or the amount of solvent used can be reduced, to ensure that the solids content of the sand-consolidating material is the same as when the sand-consolidating material is prepared using the modified nanoparticles.

[0084] Preferably, in the present invention, in order to improve the mixing effect of the components, the modified nanoparticles and / or neutral grafting reaction solution, aqueous curing agent, anti-swelling agent and solvent can be stirred at 200-1000 rpm for 5-30 min, and then optionally ultrasonicated for 10-20 min.

[0085] A fourth aspect of the present invention provides an application of the sand consolidation material described in the third aspect of the present invention in oil and gas sand consolidation.

[0086] A fifth aspect of the present invention provides a method for sand consolidation in oil and gas wells, wherein the method comprises:

[0087] Step 1, injecting nitrogen foam into the oil layer to deblock the oil layer;

[0088] Step II, injecting a chemical profile control temporary plugging agent into the oil layer to perform preliminary plugging of the oil layer;

[0089] Step III: first inject the sand consolidation material described in the third aspect of the present invention into the oil layer, and then inject the displacement fluid for displacement.

[0090] In step 1,

[0091] In a preferred embodiment of the present invention, the oil and gas well belongs to a loose sandstone reservoir, and the downhole environment of the oil and gas well includes: a water content of 70-95wt%, an average particle size of sand particles of 0.05-0.35mm, and an oil layer permeability of 0.1-3μm 2 , the formation temperature is 30-120℃.

[0092] Among them, in the present invention, nitrogen foam is injected into the oil layer and then quickly released, which can return mud, sand, colloid, asphalt and other blockages in the near-well formation to the wellbore, and then the blockages in the wellbore are flushed out. Nitrogen foam is injected and the blockages are flushed out repeatedly until the blockages in the oil layer are returned out, thereby completing the unblocking treatment of the oil layer.

[0093] In a preferred embodiment of the present invention, the nitrogen foam is a foam fluid produced by mixing nitrogen and foaming washing oil using a foam generator, wherein the amount ratio of the nitrogen to the foaming washing oil is 1000Nm 3 Nitrogen: 5-10m 3 Foaming cleaning oil.

[0094] In the present invention, the foaming oil washing liquid is an aqueous solution containing an oil washing agent and an anti-swelling agent. The oil washing agent is a surfactant that can clean crude oil from the surface of sand grains and unclog pores. The type of surfactant is not limited, and can be one or more of α-olefin sulfonate (AOS), sodium lauryl polyoxyethylene ether sulfate (AES), and sodium dodecyl sulfate (SDS). The concentration in the foaming oil washing liquid is 0.5-5wt%. The anti-swelling agent is the same as the anti-swelling agent in the third aspect of the present invention, and the concentration in the foaming oil washing liquid is 2-4wt%.

[0095] In Step II:

[0096] In a preferred embodiment of the present invention, a chemical profile control temporary plugging agent is injected into the oil layer to temporarily block large pores and high permeability layers in the oil layer, and the radius of the treated oil layer is 0.5-3m.

[0097] The present invention does not specifically limit chemical profile control temporary plugging agents; any conventional chemical profile control temporary plugging agent in the art can be used in the present invention. For example, the chemical profile control temporary plugging agent is an aqueous solution containing a polymer thickener and a breaker. The polymer thickener refers to a polymer organic substance that can increase the viscosity of clear water, and its type is not limited. For example, it can be guar gum powder, and its concentration in the chemical profile control temporary plugging agent is 0.2-0.8wt%. The breaker refers to a substance that can degrade the polymer thickener, and its type is not limited. For example, it can be ammonium persulfate, and its concentration in the chemical profile control temporary plugging agent is 0.1-0.3wt%.

[0098] In step III,

[0099] In a preferred embodiment of the present invention, a sand consolidation material is injected into the oil layer, and a displacement fluid is used to push the sand consolidation material out of the oil pipe. The radius of the treated oil layer is 0.3-1.5 m.

[0100] Among them, in the present invention, in order to ensure a better sand consolidation effect, an under-displacement method is adopted, that is, the displacement fluid only needs to push the sand consolidation material out of the oil pipe so that the sand consolidation material completely covers the oil layer section. The displacement fluid is preferably clean water.

[0101] In a preferred embodiment of the present invention, in order to ensure a better sand consolidation effect, preferably, the amount of the sand consolidation material can be calculated according to formula (1):

[0102] Among them, V is the amount of sand consolidation material, unit is m 3 ; r is the radius of the oil well sand consolidation treatment, preferably 0.3-1.5m; is the oil layer porosity, unit is %; h is the thickness of the sand producing layer, unit is m.

[0103] In a preferred embodiment of the present invention, after the displacement is completed, the well is shut in for 12-48 hours; preferably, the bottom hole temperature during the shut-in period is 50-90°C.

[0104] The sand consolidation method provided by the present invention uses nitrogen foam to treat the formation, removing blockages of silt and dead oil in the formation near the wellbore, improving the formation permeability before sand consolidation, and simultaneously removing the impact of crude oil on the surface of the sand grains on the sand consolidation material. Chemical profile adjustment and temporary plugging are used to treat the formation, temporarily blocking large pores and high permeability layers, adjusting the injection profile to prevent the sand consolidation material from leaking along the large pores in the formation or advancing into the high permeability layer. Sand consolidation material is injected into the formation to cement the loose formation sand, increasing the cementation strength of the formation rock and preventing sand production from the formation at the source. The present invention utilizes a combined "blockage removal + temporary plugging + sand consolidation" technology to enhance the overall effectiveness of chemical sand consolidation.

[0105] The following is a detailed description of the specific embodiments of the present invention. It should be understood that the specific embodiments described herein are only used to illustrate and explain the present invention and are not intended to limit the present invention.

[0106] Polyethylene glycol monostearate was purchased from Shanghai Yuanye Biotechnology Co., Ltd., product designation S51667-25g. Allyl polyoxyalkyl epoxy ether was purchased from Yangzhou Chenhua New Materials Co., Ltd., product designation H series. Polyhydroxypropyl dimethyl ammonium chloride was purchased from Jiangsu Feixiang Chemical Co., Ltd.; polyetheramine ZD123 curing agent was purchased from Zibo Zhengda Polyurethane Co., Ltd.; ZW-6112 water-based epoxy curing agent was purchased from Dongguan Zhongke Zhiyuan New Materials Technology Co., Ltd.; and SAC8325 water-based epoxy curing agent was purchased from Guangzhou Wanhua New Materials Technology Co., Ltd.

[0107] Modified Nanoparticle Preparation Example 1

[0108] (a) 100 g of nano-SiO2 (average particle size of 70 nm), 1.5 g of silane coupling agent KH550, and 300 g of glycerol were added to an HR-25D homogenizing emulsifier and stirred at 15,000 rpm for 10 min to obtain a dispersion;

[0109] (b) 40g 4-vinyl cyclohexene oxide, 20g polyethylene glycol monostearate, and 20g ethylene glycol monobutyl ether are mixed to obtain a modified treatment solution;

[0110] (c) adding all of the above dispersion to a high-temperature and high-pressure reactor, heating to 80° C., injecting nitrogen for protection, and slowly adding all of the above modified treatment liquid dropwise to the high-temperature and high-pressure reactor under stirring. After the dropwise addition is completed, 0.15 g of azobisisobutyronitrile is added; heating the high-temperature and high-pressure reactor to 150° C., reacting for 2 hours under stirring, and cooling to room temperature to obtain a grafting reaction solution;

[0111] (d) adding a sodium bicarbonate aqueous solution to the grafting reaction solution to obtain a neutral grafting reaction solution with a pH value of 7.2, and then filtering and drying the solution to obtain modified nanoparticles.

[0112] Modified Nanoparticle Preparation Example 2

[0113] (a) 100 g of nano-SiO2 (average particle size of 70 nm), 2 g of silane coupling agent KH550, and 250 g of glycerol were added to an HR-25D homogenizer and stirred at 15,000 rpm for 10 min to obtain a dispersion;

[0114] (b) 50g 4-vinyl epoxy cyclohexane, 25g polyethylene glycol monostearate, and 30g ethylene glycol monobutyl ether are mixed to obtain a modified treatment solution;

[0115] (c) adding all of the above dispersion to a high-temperature and high-pressure reactor, heating to 70° C., injecting nitrogen for protection, and slowly adding all of the above modified treatment liquid dropwise to the high-temperature and high-pressure reactor under stirring. After the dropwise addition is completed, 0.18 g of azobisisobutyronitrile is added; heating the high-temperature and high-pressure reactor to 160° C., reacting for 3 hours under stirring, and cooling to room temperature to obtain a grafting reaction solution;

[0116] (d) adding a sodium bicarbonate aqueous solution to the grafting reaction solution to obtain a neutral grafting reaction solution with a pH value of 7.0, and then filtering and drying the solution to obtain modified nanoparticles.

[0117] Modified Nanoparticle Preparation Example 3

[0118] (a) 100 g of nano-SiO2 (average particle size of 70 nm), 1 g of silane coupling agent KH550, and 350 g of glycerol were added to an HR-25D homogenizing emulsifier and stirred at 15,000 rpm for 10 min to obtain a dispersion;

[0119] (b) 30g 4-vinyl cyclohexene oxide, 15g polyethylene glycol monostearate, and 25g ethylene glycol monobutyl ether are mixed to obtain a modified treatment solution;

[0120] (c) adding all of the above dispersion to a high-temperature and high-pressure reactor, heating it to 90° C., injecting nitrogen for protection, and slowly adding all of the above modified treatment liquid dropwise to the high-temperature and high-pressure reactor under stirring. After the dropwise addition is completed, 0.12 g of azobisisobutyronitrile is added; heating the high-temperature and high-pressure reactor to 140° C., reacting for 4 hours under stirring, and cooling to room temperature to obtain a grafting reaction solution;

[0121] (d) adding a sodium bicarbonate aqueous solution to the grafting reaction solution to obtain a neutral grafting reaction solution with a pH value of 7.5, and then filtering and drying the solution to obtain modified nanoparticles.

[0122] Modified Nanoparticle Preparation Example 4

[0123] (a) 100 g of carbon nanotubes (average particle size of 50 nm), 0.5 g of methyltriethoxysiloxane (a silane coupling agent), and 200 g of ethanol were added to an HR-25D homogenizing emulsifier and stirred at 15,000 rpm for 10 min to obtain a dispersion;

[0124] (b) 20 g of allyl polyoxyalkyl epoxy ether, 10 g of 5-hydroxy-1,3-benzenedisulfonic acid, and 10 g of benzyl alcohol were mixed to obtain a modified treatment solution;

[0125] (c) adding all of the above dispersion to a high-temperature and high-pressure reactor, heating it to 60° C., injecting nitrogen for protection, and slowly adding all of the above modified treatment liquid dropwise to the high-temperature and high-pressure reactor under stirring. After the dropwise addition is completed, 0.1 g of cerium oxide is added; heating the high-temperature and high-pressure reactor to 130° C., reacting for 5 hours under stirring, and cooling to room temperature to obtain a grafting reaction solution;

[0126] (d) adding ammonia water to the grafting reaction solution to obtain a neutral grafting reaction solution with a pH value of 7.8, and then filtering and drying the solution to obtain modified nanoparticles.

[0127] Modified Nanoparticle Preparation Example 5

[0128] (a) 100 g of nano-titanium oxide (average particle size of 30 nm), 2.5 g of vinyl triethoxysilane (silane coupling agent), and 400 g of triethylene glycol were added to an HR-25D homogenizing emulsifier and stirred at 15,000 rpm for 10 min to obtain a dispersion;

[0129] (b) 60 g of (S)-2-(but-3-enyl) ethylene oxide, 30 g of isomeric alcohol polyoxyethylene ether, and 40 g of diethylene glycol were mixed to obtain a modified treatment solution;

[0130] (c) adding all of the above dispersion to a high-temperature and high-pressure reactor, heating to 100° C., injecting nitrogen for protection, and slowly adding all of the above modified treatment liquid dropwise to the high-temperature and high-pressure reactor under stirring. After the dropwise addition is completed, 0.2 g of sodium caprolactam is added; heating the high-temperature and high-pressure reactor to 170° C., reacting for 1 hour under stirring, and cooling to room temperature to obtain a grafting reaction solution;

[0131] (d) adding an aqueous potassium carbonate solution to the grafting reaction solution to obtain a neutral grafting reaction solution with a pH value of 8, and then filtering and drying the solution to obtain modified nanoparticles.

[0132] Sand consolidation material preparation example 1

[0133] (1) Prepare a neutral grafting reaction solution by referring to Example 1 for preparing modified nanoparticles;

[0134] (2) The neutral grafting reaction solution, polyetheramine ZD123 curing agent aqueous solution, potassium chloride aqueous solution and water were stirred at 600 rpm for 10 minutes, and then ultrasonicated for 15 minutes to obtain a sand-consolidating material;

[0135] The sand-consolidating material has a solid content of 30 wt%, 100 g of modified nanoparticles, 8 g of polyetheramine ZD123 curing agent, and 2 g of potassium chloride. The viscosity at 25°C is ? mPa·s. (The viscosity at 25°C is 10-30 mPa·s, preferably 15-25 mPa·s. In Examples 1-3, the viscosity is between 15 and 25. The viscosity is tested using?)

[0136] Sand consolidation material preparation example 2

[0137] (1) Prepare a neutral grafting reaction solution by referring to Example 2 for preparing modified nanoparticles;

[0138] (2) stirring the neutral grafting reaction solution, dimethylimidazole aqueous solution, potassium chloride aqueous solution and water at 600 rpm for 10 minutes, and then ultrasonicating for 15 minutes to obtain a sand consolidation material;

[0139] Among them, the solid content of the sand-consolidating material is 25wt%, the content of modified nanoparticles is 100g, the content of dimethylimidazole is 10g, and the content of potassium chloride is 4g.

[0140] Sand consolidation material preparation example 3

[0141] (1) Prepare a neutral grafting reaction solution by referring to Example 3 for preparing modified nanoparticles;

[0142] (2) The neutral grafting reaction solution, polyetheramine ZD123 curing agent aqueous solution, potassium chloride aqueous solution and water were stirred at 600 rpm for 10 minutes, and then ultrasonicated for 15 minutes to obtain a sand-consolidating material;

[0143] Among them, the solid content of the sand-consolidating material is 35wt%, the content of the modified nanoparticles is 100g, the content of the polyetheramine ZD123 curing agent is 12g, and the content of potassium chloride is 3g.

[0144] Sand consolidation material preparation example 4

[0145] (1) Prepare a neutral grafting reaction solution by referring to Example 4 for preparing modified nanoparticles;

[0146] (2) The neutral grafting reaction solution, ZW-6112 waterborne epoxy curing agent, sodium chloride and water were stirred at 600 rpm for 10 minutes, and then ultrasonicated for 15 minutes to obtain a sand-consolidating material;

[0147] Among them, the solid content of the sand-consolidating material is 20wt%, the content of the modified nanoparticles is 100g, the content of the ZW-6112 water-based epoxy curing agent is 6g, and the content of sodium chloride is 1g.

[0148] Sand consolidation material preparation example 5

[0149] (1) Prepare modified nanoparticles according to Example 5 for preparing modified nanoparticles;

[0150] (2) The modified nanoparticles, SAC8325 waterborne epoxy curing agent, polyhydroxypropyl dimethyl ammonium chloride and water were stirred at 600 rpm for 10 minutes, and then ultrasonicated for 15 minutes to obtain a sand consolidation material;

[0151] Among them, the solid content of the sand-consolidating material is 40wt%, the content of the modified nanoparticles is 100g, the content of the SAC8325 water-based epoxy curing agent is 15g, and the content of polyhydroxypropyl dimethyl ammonium chloride is 6g.

[0152] Comparative Example 1

[0153] 60 g of phenolic resin (model 219, commercially available), 40 g of ethanol, 90 g of water and 10 g of curing agent NL were mixed uniformly to obtain a phenolic resin sand consolidating agent.

[0154] Comparative Example 2

[0155] 60 g of epoxy resin (model E44, commercially available), 80 g of ethanol and 10 g of curing agent T31 were mixed uniformly to obtain an epoxy resin curing agent.

[0156] Test Example 1

[0157] Infrared spectroscopy analysis of the modified nanoparticles prepared in Examples 1-5 of the Modified Nanoparticle Preparation Methods revealed that the crosslinking reactive groups and hydrophilic groups were grafted onto the inorganic nanoparticles via the coupling groups. The contents of coupling agent groups, crosslinking reactive groups, and hydrophilic groups, based on the inorganic nanoparticles, are shown in Table 1. The average particle size of the modified nanoparticles was measured using a laser particle size analyzer.

[0158] Table 1

[0159] Here, taking the infrared spectrum characterization of the modified nanoparticles prepared in Example 1 for preparing modified nanoparticles as an example, FIG3 is an infrared spectrum diagram of the modified nanoparticles prepared in Example 1 for preparing modified nanoparticles.

[0160] As shown in Figure 3, at 1710 cm -1 The absorption peak at 1399 cm corresponds to the stretching vibration of the carboxyl group. -1 The characteristic peak of the hydroxyl group is at 927 cm -1 The stretching vibration absorption peak of epoxy group is at 1176cm -1 The weak absorption peak at 1038cm corresponds to the stretching vibration of the CO-Si bond generated by the cross-linking reaction group and the silane coupling agent. -1The weak absorption peak at corresponds to the bond between the hydrophilic group and the hydrophobic group on the coupling group. From the above analysis results, it can be seen that the hydrophilic group and the cross-linking reaction group are successfully bonded to the surface of nano-SiO2.

[0161] Test Example 2

[0162] The sand consolidation performance of the sand consolidation materials prepared in Examples 1-5 of the Sand Consolidation Material, the phenolic resin sand consolidating agent prepared in Comparative Example 1, and the epoxy resin curing agent prepared in Comparative Example 2 was evaluated. The test samples were first prepared into consolidated cores, and then the permeability of the consolidated cores was tested according to the method of SY / T 5276-2000 "Test Method for Flexural Strength, Compressive Strength, and Permeability of Artificial Cores for Chemical Sand Control". The results are shown in Table 2. The compressive strength of the consolidated cores was tested according to the method of SY / T 5276-2000 "Test Method for Flexural Strength, Compressive Strength, and Permeability of Artificial Cores for Chemical Sand Control". The results are shown in Table 3.

[0163] The preparation method of the consolidated core is as follows:

[0164] (1) Connect one end of a Φ25×50mm glass tube to a vacuum filtration device to form a sand consolidation experimental device; take 20g of formation sand (sand particle size is 0.38-0.83mm) and put it into the Φ25×50mm glass tube, start the vacuum pump for filtration, pour in clean water to moisten the formation sand, then pour in the sample to be tested and let it completely soak into the formation sand, and stop filtration; seal both ends of the glass tube and fix it with a clamp to keep the formation sand in a compacted state, put it in a water bath, set the temperature to 50℃, and after curing for 24 hours, take it out and break the glass tube to obtain a consolidated core;

[0165] (2) According to the above method, the particle size of the formation sand was changed (the particle sizes of the formation sand were 0.38-0.83 mm, 0.212-0.38 mm, 0.18-0.25 mm, 0.075-0.15 mm, and 0.053-0.106 mm, respectively) to prepare a series of consolidated cores.

[0166] Table 2

[0167] Table 3

[0168] Among them, the higher the permeability and the greater the compressive strength, the better the sand consolidation effect of the sand consolidation material. As can be seen from Tables 2 and 3, the consolidated cores prepared using the sand consolidation material prepared in the present invention have high permeability and high compressive strength, and thus the sand consolidation material has a very excellent sand consolidation effect.

[0169] However, the permeability and compressive strength of the consolidated cores prepared using phenolic resin sand consolidation agents and epoxy resin sand consolidation agents were significantly worse than those of the present invention when the formation sand particle size was 0.38-0.83mm, 0.212-0.38mm, and 0.18-0.25mm, respectively. Moreover, when the formation sand particle size was 0.075-0.15mm and 0.053-0.106mm, due to the high system viscosity of the phenolic resin sand consolidation agents and epoxy resin sand consolidation agents, they could not be completely absorbed into the formation sand using a vacuum filtration device, resulting in an incomplete consolidated core with the upper portion completely solidified and the lower portion completely uncemented, making it impossible to test the compressive strength.

[0170] The consolidated rock core (formation sand particle size 0.212-0.38 mm) prepared using the sand consolidation material in Example 1 and the consolidated rock core (formation sand particle size 0.212-0.38 mm) prepared using the phenolic resin sand consolidating agent in Comparative Example 1 were characterized by SEM, and the results are shown in Figures 4 and 5.

[0171] As shown in Figure 4 , in the consolidated core prepared using the sand consolidation material of Example 1, the sand consolidation material formed a uniform, smooth, and high-strength solidified film on the surface of the formation sand, with the solidified material primarily located at the contact points of the sand grains, without clogging the pore channels. As shown in Figure 5 , in the consolidated core prepared using the phenolic resin sand consolidation agent of Comparative Example 1, the solidified material was unevenly distributed within the pores of the formation sand and severely clogged the pore channels.

[0172] Application Example 1

[0173] The sand consolidation material in Example 1 of the preparation of sand consolidation material was applied in Well XX1 of Liaohe Oilfield. Well XX1 belongs to a loose sandstone reservoir with a well depth of 1400m and a 4-inch side drilling slim hole. In March 2023, the well was shut down due to sand production and pump jamming. The wellbore was buried in sand for 109.5m, the oil layer thickness was 12.5m, the oil layer porosity was 28.4%, the water content was 86.7wt%, the average particle size of the sand particles was 0.125mm, and the oil layer permeability was 0.85-1.27μm. 2 , the formation temperature was 55° C. In order to restore normal production of the well, the sand consolidation material prepared in Example 1 of the present invention was used to carry out sand consolidation operations. The specific method is as follows:

[0174] Step I: inject nitrogen foam into the oil layer at a speed of 2000 Nm 3 Nitrogen injection 15m 3 The foaming oil washing liquid is used to remove the blockage of the oil layer; wherein the foaming oil washing liquid adopts 2wt% α-olefin sulfonate (AOS) and 2wt% potassium chloride aqueous solution.

[0175] Step II: Use a 700 pump truck to inject 30m 3A chemical profile control temporary plugging agent is used to temporarily plug large pores and high permeability layers, thereby preliminarily sealing the oil layer. The chemical profile control temporary plugging agent is prepared from 0.5 wt% guanidine gum powder, 0.2 wt% ammonium persulfate, and water.

[0176] Step III, first injecting the sand consolidation material prepared in Example 1 into the oil layer, and then injecting the displacement fluid for displacement;

[0177] The designed sand consolidation radius is 0.8m. The amount of sand consolidation material is calculated according to the following formula: 7.13m 3 The construction displacement was 500L / min and the construction pressure was 9MPa. After construction, the well was shut down and solidified for 48 hours and production was successfully resumed.

[0178] Among them, V is the amount of sand consolidation material, unit is m 3 ; r is the radius of sand consolidation treatment; is the oil layer porosity, unit is %; h is the oil layer thickness, unit is m;

[0179] Before the measures were taken, the well was repeatedly sanded and pumped, with a pump inspection cycle of only 211 days. After the measures were taken, the initial daily liquid production increased by 28.1% and the daily oil production increased by 35%. As of now, the effective period of sand consolidation has reached 547 days, and the well is still producing normally, showing a good sand consolidation effect.

[0180] Application Example 2

[0181] The sand consolidation material prepared in Example 1 of the present invention was used in 4 wells in the same block. The on-site implementation effect is shown in Table 4.

[0182] Table 4

[0183] Field implementation results show that sand consolidation measures have not impacted production, with the longest effective sand control period exceeding 547 days, maintaining normal production. In contrast, 43% of wells using other chemical sand consolidation technologies in the same area experienced production declines, with an average effective sand control period of only 182 days. In comparison, the sand consolidation material provided by the present invention offers superior sand consolidation results and distinct advantages.

[0184] The preferred embodiments of the present invention are described in detail above, but the present invention is not limited thereto. Within the technical concept of the present invention, various simple variations of the technical solution of the present invention may be made, including combining the various technical features in any other appropriate manner. To avoid unnecessary repetition, the present invention will not further describe various possible combinations. These simple variations and combinations should also be regarded as the contents disclosed by the present invention and fall within the scope of protection of the present invention.

Claims

1. A modified nanoparticle characterized in that: The modified nanoparticles include inorganic nanoparticles, coupling groups grafted on the surfaces of the inorganic nanoparticles, and cross-linking reaction groups and hydrophilic groups grafted on the coupling groups.

2. The modified nanoparticle according to claim 1, wherein Based on the weight of the inorganic nanoparticles, the content of the coupling groups is 0.1-2.3 wt %, the content of the cross-linking reaction groups is 16-57 wt %, and the content of the hydrophilic groups is 4-30 wt %.

3. The modified nanoparticle according to claim 1, wherein The inorganic nanoparticles are selected from one or more of nano-silicon dioxide, nano-carbon fibers, carbon nanotubes, nano-titanium oxide, and nano-aluminum oxide.

4. The modified nanoparticle according to claim 1, wherein The coupling group is derived from a silane coupling agent.

5. The modified nanoparticle according to claim 4, wherein The silane coupling agent is selected from one or more of 3-aminopropyltriethoxysilane, methyltriethoxysiloxane, γ-(2,3-epoxypropyloxy)propyltrimethoxysilane, vinyltrimethylsilane and vinyltriethoxysilane.

6. The modified nanoparticle according to claim 1, wherein The cross-linking reaction group is derived from a cross-linking organic substance containing an alkenyl group and an epoxy group.

7. The modified nanoparticle according to claim 6, wherein The cross-linked organic matter is selected from small molecule cross-linked organic matter and / or cross-linked polymer; Wherein, the small molecule cross-linked organic compound is selected from one or more of 4-vinyl cyclohexene oxide, (R)-2-vinyl oxirane, (S)-2-(but-3-enyl)oxirane; Wherein, the cross-linked polymer is selected from one or more of allyl polyoxyalkyl epoxy ether, allyl polyoxyethylene ether epoxy ether, and allyl polyoxyethylene polyoxypropylene epoxy ether.

8. The modified nanoparticle according to claim 1, wherein The hydrophilic group is derived from a hydrophilic organic substance containing a hydrophilic group; wherein the hydrophilic group is selected from at least one of a hydroxyl group, an ether group, a carboxyl group, and a sulfonic acid group.

9. The modified nanoparticle according to claim 8, wherein The hydrophilic organic matter is selected from small molecule hydrophilic organic matter and / or hydrophilic polymer; Among them, the small molecule hydrophilic organic matter is selected from one or more of acrylic acid-(meth)acrylate, 3,4-dihydroxybenzene acrylic acid, 4-hydroxybenzenesulfonic acid, 2-hydroxybenzenesulfonic acid, 3-hydroxybenzenesulfonic acid, 5-hydroxy-1,3-benzenedisulfonic acid, and 2,4-dihydroxybenzenesulfonic acid, and the hydrophilic polymer is selected from one or more of polyethylene glycol monostearate, polyether nonionic surfactant, and isomeric alcohol polyoxyethylene ether.

10. A method for preparing the modified nanoparticles according to any one of claims 1 to 9, The characteristic is that the method comprises the following steps: (a) mixing inorganic nanoparticles, a coupling agent and a dispersing solvent to obtain a dispersion; (b) mixing the cross-linking organic matter, the hydrophilic organic matter and the diluent to obtain a modified treatment solution; (c) contacting the dispersion, the modified treatment solution and a catalyst to carry out a grafting reaction to obtain a grafting reaction solution; (d) first adding a pH adjuster to the grafting reaction solution to obtain a neutral grafting reaction solution, and then separating the neutral grafting reaction solution to obtain modified nanoparticles.

11. The preparation method according to claim 10, wherein: In step (a), 100 parts by weight of inorganic nanoparticles, 0.5-2.5 parts by weight of a coupling agent and 200-400 parts by weight of a dispersing solvent are mixed to obtain an inorganic nanoparticle dispersion; In step (b), 20-60 parts by weight of a cross-linking organic substance, 5-35 parts by weight of a hydrophilic organic substance, and 10-40 parts by weight of a diluent are mixed to obtain a modified treatment solution; In step (c), the catalyst is added in an amount of 0.1-0.2 parts by weight based on 100 parts by weight of the inorganic nanoparticles.

12. The preparation method according to claim 10, wherein: The catalyst is selected from one or more of azobisisobutyronitrile, cerium oxide, and sodium caprolactam.

13. The preparation method according to claim 10, wherein: The operation conditions of the grafting reaction include: reaction temperature of 120° C.-180° C., and reaction time of 1-6 h.

14. A sand consolidation material, characterized in that: By weight, the raw materials for preparing the sand-fixing material include the modified nanoparticles, water-based curing agent, anti-swelling agent and solvent described in any one of claims 1 to 9; wherein the solid content of the sand-fixing material is 10-50wt%, and the mass ratio of the modified nanoparticles, water-based curing agent and anti-swelling agent is 100:5-20:1-6.

15. The sand consolidation material according to claim 14, wherein: The water-based curing agent is selected from one or more of ZW-6112 water-based epoxy curing agent, DP-03 water-based epoxy curing agent, CYDHD-220 water-based epoxy curing agent, SAC8325 water-based epoxy curing agent, polyetheramine D230 curing agent, polyetheramine ZD123 curing agent, imidazole, and dimethylimidazole; The anti-swelling agent is selected from one or more of inorganic salt anti-swelling agents, organic quaternary ammonium salt anti-swelling agents, and organic cationic polymer anti-swelling agents.

16. The sand consolidation material according to claim 14, wherein: The preparation method of the sand consolidation material comprises the following steps: (1) preparing modified nanoparticles and / or neutral grafting reaction solution; (2) The modified nanoparticles and / or the neutral grafting reaction liquid, the aqueous curing agent, the anti-swelling agent and the solvent are uniformly mixed to obtain a sand consolidation material.

17. Use of the sand consolidation material according to any one of claims 14 to 16 in sand consolidation of oil and gas wells.

18. A method for sand consolidation in oil and gas wells, characterized in that: The method comprises: Step I, injecting nitrogen foam into the oil layer to remove blockage in the oil layer; Step II, injecting a chemical profile control temporary plugging agent into the oil layer to preliminarily plug the oil layer; Step III, first inject the sand consolidation material described in any one of claims 14 to 16 into the oil layer, and then inject the displacement fluid for displacement.

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