Soft formation skeleton reconstruction and acid treatment synergistic stimulation method

Abstract

The application discloses a soft formation skeleton reconstruction and acid treatment synergistic stimulation method, and belongs to the technical field of stimulation reconstruction of oil and gas fields. c Determine whether it is a soft formation and calculate the fracture pressure P f ; sequentially inject a pre-separation liquid, a skeleton reconstruction liquid, a main body acid liquid, a post-stable protection liquid and a displacement liquid, and then shut down and flow back. The skeleton reconstruction liquid is composed of a film-forming protection component and a crystalline bridge component, can form a protective film and a crystalline bridge structure at the pore throat boundary, the particle contact, the argillaceous filling area and the calcareous mineral surface; the main body acid liquid is used for matrix acidification or acid fracturing; and the post-stable protection liquid is used for reinforcing the acid-etched channel wall surface. The method can reduce the risks of skeleton weakening, particle falling and acid post-channel instability caused by acid treatment, and improves the reconstruction effect of the soft formation acidification or acid fracturing.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field production enhancement and transformation technology, specifically involving a method for synergistic production enhancement through soft formation framework reconstruction and acid treatment. Background Technology

[0002] As conventional, easily exploitable oil and gas resources gradually decrease, low-strength, weakly cemented, high-muddy, and highly heterogeneous formations are becoming increasingly important targets for oil and gas well production enhancement. In engineering, these formations, which are prone to skeleton instability, particle shedding, fine particle migration, pore throat blockage, or decreased channel conductivity during development, are generally referred to as soft formations.

[0003] For this type of formation, acidizing and acid fracturing are commonly used production enhancement techniques. Acidizing can clear pore throats by dissolving near-wellbore blockages, carbonate minerals, or acid-soluble components; acid fracturing can create a non-uniform acid etching morphology in fractures and maintain a certain conductivity by relying on the residual undulations of the acid-etched wall. Existing acid treatment technologies mainly focus on acid systems, slow reactions, deep penetration, fracture conductivity, and optimization of construction parameters, resulting in various acidizing, acid fracturing, and composite acid processes.

[0004] In acid fracturing processes, existing technologies primarily improve the acid's contact distance and the conductivity of acid-etched fractures through methods such as temporary plugging, redirection, and flow rate optimization. For example, "Temporary Covering Particles on the Fracture Wall and Its Temporary Covering Acid Fracturing Method" (CN113565486A) uses temporary covering particles to cover the fracture wall, thereby improving the conductivity of acid-etched fractures and the effective period of acid fracturing; "A Method for Optimizing the Flow Rate of Multi-Stage Alternating Acid Fracturing in Carbonate Reservoirs" (CN110630240B) optimizes the flow rate of multi-stage alternating acid fracturing through parameters such as surface-to-volume ratio; and "Foam Slug Diversion Acidizing Process" (CN101126314A) utilizes foam slugs to temporarily plug high-permeability layers, redirecting the acid to low-permeability layers. While these technologies can improve acid distribution, increase acid utilization, or enhance fracture conductivity, their core remains improving the acid fracturing effect through acid dissolution, temporary plugging and redirection, or optimization of construction parameters. They do not address the problems of low skeleton strength, weak pore-throat boundaries, and easy instability of channels after acid treatment in soft formations.

[0005] Regarding acid materials, existing technologies primarily enhance deep penetration capabilities by increasing acid viscosity and reducing the acid-rock reaction rate. For example, the "Controllable Viscosity Acid System for Acid Fracturing in Carbonate Reservoirs" (CN101314713A) reduces filtration loss and acid-rock reaction rate through controllable viscosity acid; the "Unblocking Agent Suitable for Acidizing Complex Lithological Reservoirs" (CN103484088A) achieves unblocking of complex lithological reservoirs by slowly generating acidic components; and the "Injection Method of Solid Slow-Release Acid" (CN111364964B) and "Preparation Method of Encapsulated Solid Hydrochloric Acid" (CN103911139B) achieve delayed release through solid acid or encapsulated acid. These technologies mainly address issues such as excessively rapid acid reactions, insufficient deep acidification, or low unblocking efficiency. However, for soft formations, while acid dissolves blockages and expands seepage channels, it may still weaken particle contact, clay cementation, and pore throat boundary strength, resulting in insufficient post-acid channel support and making it difficult to maintain the increased production effect in the long term.

[0006] In terms of sand control and consolidation, existing technologies typically improve particle bonding strength or rock surface hardness through methods such as resins, polymers, inorganic cements, chemical self-polymerization systems, or mineral alteration. For example, "A Sand Control and Consolidation Agent" (CN102838975A) uses a resin film to coat feldspar sand cores and combines it with cement to improve the sand control and consolidation effect of oil and water wells; "A Construction Method for Self-polymerization Sand Control in Oil and Water Wells" (CN110454120B) achieves formation sand and gravel self-polymerization and reconsolidation by injecting self-polymerization liquid, self-polymerization aid and cementing liquid in stages; "Reinforcement Material and Reinforcement Method for Permeable Hydraulic Deteriorated Loose Rocks" (CN101607833A) forms inorganic adhesive reinforcement products in loose rocks through a phosphorus source, calcium source and alcohol solvent system; "Calcium Carbonate Biomineralization Reinforcement Method for Calcium Carbonate Stone Cultural Relics" (CN100519484C) induces calcium carbonate nucleation and directional crystallization, connects loose particles and improves the surface stability of stone materials. The above-mentioned technologies can improve local strength and surface hardness, but they are mostly based on cementation and filling, and surface mineral precipitation. If the reinforcement products are deposited excessively in the pore throat or main seepage channel, it can easily cause pore throat blockage and permeability loss. At the same time, they are usually not integrated with the subsequent acidizing or acid fracturing process, making it difficult to simultaneously achieve the stability of the soft formation framework, the construction of acid etching channels, and the long-term stability of the post-acid channels.

[0007] Therefore, for soft formations, acidizing or acid fracturing alone is insufficient to simultaneously achieve acid channel formation and formation framework stability, while consolidation or sand control alone can easily lead to pore throat blockage and permeability loss. The key to this type of formation stimulation is not simply to enlarge seepage channels, but to maintain the long-term stability of the formation framework and channel walls while forming acid-etched pore throats, wormholes, or acid-etched fractures. Current technologies still struggle to simultaneously meet the requirements of framework stability, acid channel construction, and long-term post-acidification effectiveness.

[0008] Based on this, it is necessary to propose a method for synergistic production enhancement of soft formations through framework reconstruction and acid treatment. Before the main acid treatment, the bearing capacity of the formation framework and the stability of the pore throat boundary should be improved. Then, acidizing or acid fracturing treatment should be carried out according to the transformation needs. After the acid treatment, stabilization and effectiveness maintenance should be carried out to reduce the risk of framework weakening caused by single acid treatment and the risk of pore throat blockage caused by single consolidation treatment, so as to achieve stable production enhancement of soft formations. Summary of the Invention

[0009] The purpose of this invention is to provide a method for synergistic production enhancement through soft formation framework reconstruction and acid treatment, in order to solve the problems in existing soft formation acidification or acid fracturing, where single acid treatment easily weakens the strength of the formation framework and leads to poor stability of the post-acid channel, while single consolidation treatment is prone to pore throat blockage and permeability loss due to cementation product deposition, making it difficult to simultaneously ensure formation framework stability, acid etching channel construction and long-term effectiveness.

[0010] To achieve the above objectives, the present invention provides the following technical solution.

[0011] A method for synergistically increasing production through soft formation framework reconstruction and acid treatment includes the following steps: (1) Collect target stratum data, based on uniaxial compressive strength R c Determine whether the target stratum is a soft stratum; (2) Calculate the target formation fracture pressure P f ; (3) The solution is injected in stages in the order of pre-isolation solution, skeleton reconstruction solution, main acid solution, post-stabilizing and maintaining solution and displacement solution; the acid treatment method is selected from either matrix acidification or acid fracturing. (4) At a pressure lower than the target formation fracturing pressure P f Under the specified conditions, inject pre-placement fluid; the construction discharge rate is 0.5–3.0 m³. 3 / min, the injection volume is 1.0 to 1.5 times the effective wellbore volume of the pre-isolation fluid; the pre-isolation fluid is used to isolate residual wellbore fluid and formation fluid, reducing the impact of incompatibility between the subsequent skeleton reconstruction fluid and residual wellbore fluid or formation water; (5) At a pressure lower than the target formation fracturing pressure P f Under the specified conditions, the skeleton reconstruction fluid is injected, with a construction flow rate of 0.5–3.0 m³. 3 / min, the injection volume is 0.5 to 1.5 times the pore volume of the modified well section; the skeleton reconstruction fluid is used to reconstruct the skeleton of the soft formation pore throat boundary, particle contact area, clay filling area and calcareous mineral surface before the main acid treatment; (6) Well shut-in reaction after the skeleton reconstruction fluid is injected; when the target formation temperature T is higher than 120℃, shut-in for 2 to 12 hours; when the target formation temperature T is not higher than 120℃, shut-in for 12 to 48 hours, so that the skeleton reconstruction fluid can fully act on the target formation and form a reconstructed skeleton that has both surface protection and crystal bridging functions. (7) Inject the main acid solution into the target formation after skeleton reconstruction. The injection methods of the main acid solution include the following two construction conditions: ① Synergistic production enhancement condition of skeleton reconstruction and matrix acidification: at a pressure lower than the target formation fracturing pressure P f Under the specified conditions, the main acid solution is injected, with a discharge rate of 0.5–3.0 m³. 3 / min, the injection volume is 1.0 to 3.0 times the pore volume of the modified well section; ② Synergistic production enhancement condition of skeleton reconstruction and acid fracturing: at a pressure higher than the target formation fracture pressure P f Under the specified conditions, the main acid solution is injected, with a discharge rate of 2.0–8.0 m³ / h. 3 / min, injection volume is 2-6m per meter of working section. 3 Configuration; the main acid solution is used to dissolve near-wellbore plugs, acid-soluble fillers, or form acid-etched fractures based on the reconstructed framework; (8) After the main acid injection is completed, the pressure is lower than the target formation fracturing pressure P. f Under these conditions, a post-treatment stabilizing and maintaining fluid is injected, with a discharge rate of 0.5–3.0 m³. 3 / min, the injection volume is 0.2 to 0.5 times the pore volume of the modified well section; the post-positioned stabilizing and maintaining fluid is used to reinforce and protect the acid-etched pore throat, acid-etched wormhole or acid-etched fracture wall, and reduce the risk of post-acid channel closure, peeling and fine particle migration; (9) At a pressure lower than the target formation fracturing pressure P f Under the specified conditions, the displacement fluid is injected, with a discharge rate of 0.5–3.0 m³ / h. 3 / min, the injection volume is 1.2 to 1.5 times the total displacement volume of the injection pipeline and injection string; (10) After the replacement fluid is injected, the well is shut in for 1 to 24 hours, and then the well is opened for backflow to form a stable acid etching flow channel in the target formation.

[0012] Preferably, the soft stratum has a uniaxial compressive strength R c ≤30MPa is used as the main control discrimination parameter.

[0013] Preferably, the target formation fracturing pressure P f according to The calculation is performed, where αF is the target formation fracture pressure gradient and H is the well depth; when the length of the working well section is large, H is taken as the depth of the midpoint of the working well section.

[0014] Preferably, the pre-isolation solution is selected from one of water, 1wt% to 5wt% KCl solution, and 1wt% to 5wt% NH4Cl solution.

[0015] Preferably, the skeleton reconstruction solution is prepared by distributing the following mass fractions: 5wt% to 20wt% film-forming protective component, 5wt% to 20wt% crystallization bridging component, and the balance being water.

[0016] Preferably, the film-forming protective component is prepared by distributing the following mass fractions: 5 wt%–30 wt% film-forming phosphonate, 5 wt%–30 wt% film-forming carboxylate, 1 wt%–10 wt% surfactant, with the balance being water; the film-forming phosphonate is one or more of aminotrimethylphosphonic acid, hydroxyethylidene diphosphonic acid, ethylenediaminetetramethylidene phosphonic acid, and sodium diethylenetriaminepentamethylidene phosphonate; the film-forming carboxylate is one or more of sodium citrate, sodium gluconate, sodium tartrate, sodium oxalate, sodium polyacrylate, and hydrolyzed polymaleic anhydride; and the surfactant is one or more of sodium dodecylbenzenesulfonate, sodium dodecyl sulfate, dodecyltrimethylammonium chloride, hexadecyltrimethylammonium bromide, Tween 80, and cocamidopropyl betaine.

[0017] Preferably, the crystal bridging component is prepared by distributing the following mass fractions: 10wt%–40wt% mineral remodeling agent, 1wt%–10wt% interface modifier, 1wt%–10wt% crystal morphology modifier, with the balance being water; the mineral remodeling agent is one or more of oxalic acid, sodium oxalate, ammonium oxalate, zinc chloride, zinc sulfate, sodium silicate, and sodium metasilicate; the interface modifier is one or more of dodecyltrimethylammonium chloride, tetradecyltrimethylammonium chloride, and hexadecyltrimethylammonium bromide; and the crystal morphology modifier is one or more of methanol, ethanol, isopropanol, ethylene glycol, and glycerol.

[0018] Preferably, the main acid solution is prepared by distributing the following mass fractions: 3wt%–15wt% acid solution, 3wt%–5wt% comprehensive additives, and the balance being water; the acid solution is one or more of hydrochloric acid, formic acid, acetic acid, citric acid, oxalic acid, aminosulfonic acid, and ethylenediaminetetraacetic acid; the comprehensive additives are prepared by distributing the following mass fractions: 20wt%–60wt% corrosion inhibitor, 10wt%–40wt% surfactant, 10wt%–40wt% miscible solvent, and the balance being water; the corrosion inhibitor… The agent is one or more of hexamethylenetetramine, thiourea, propargyl alcohol, imidazoline oleate, dodecylpyridine chloride, hexadecylpyridine chloride, and dodecyltrimethylammonium chloride; the surfactant is one or more of sodium dodecylbenzenesulfonate, sodium dodecyl sulfate, dodecyltrimethylammonium chloride, hexadecyltrimethylammonium bromide, Tween 80, and cocamidopropyl betaine; the miscible solvent is one or more of diethylene glycol butyl ether, propylene glycol methyl ether, dipropylene glycol methyl ether, methanol, ethanol, and isopropanol.

[0019] Preferably, the post-stabilizing and maintaining solution is prepared by distributing the following mass fractions: 0.5wt%–3wt% clay stabilizer, 0.1wt%–2wt% corrosion and scale inhibitor, 0.5wt%–5wt% film-forming reinforcing agent, with the balance being water; the clay stabilizer is one or more of potassium chloride, ammonium chloride, choline chloride, dodecyltrimethylammonium chloride, and cationic polyacrylamide; the corrosion and scale inhibitor is one or more of aminotrimethylphosphonic acid, hydroxyethylidene diphosphonic acid, hydrolyzed polymaleic anhydride, sodium polyacrylate, and imidazoline oleate; and the film-forming reinforcing agent is one or more of sodium citrate, sodium gluconate, sodium oxalate, ammonium oxalate, sodium silicate, sodium metasilicate, zinc chloride, and zinc sulfate.

[0020] Preferably, the displacement solution is selected from one of the following: 1wt% to 5wt% NH4Cl solution, 1wt% to 5wt% KCl solution, water, or formation water.

[0021] The mechanism of action of this invention is as follows: Single acid treatment typically relies on the acid solution to dissolve formation minerals or blockages to form seepage channels, which is easily accompanied by weakening of the formation skeleton and instability of pore-throat boundaries. In contrast, this invention, before the main acid treatment, injects a skeleton reconstruction fluid under conditions lower than the target formation fracturing pressure. This fluid enters the pore-throat boundaries, particle contact areas, clay-filled regions, and calcareous mineral surfaces of soft formations, pre-reconstructing the formation skeleton (see...). Figure 1 ).

[0022] The film-forming protective components in the framework reconstruction fluid primarily function to protect and stabilize the surface. Specifically, film-forming phosphonates and carboxylates can complex, adsorb, or deposit with the surfaces of calcareous minerals, acid-soluble cements, or metal ions, forming a protective film or surface-stabilizing layer on the calcareous mineral surfaces and fracture walls, thereby increasing particle surface hardness and acid corrosion resistance. Surfactants improve the distribution of the framework reconstruction fluid on pore throats, particle surfaces, and fracture walls, allowing the film-forming protective components to act more uniformly on the target formation surface. Through these actions, the film-forming protective components can mitigate the excessive dissolution of the soft formation framework by the main acid solution, reducing the risk of rapid framework weakening during acid treatment.

[0023] The crystalline bridging components in the framework reconstruction fluid primarily function as mineral reconstructors and crystallization bridges. Specifically, the mineral reconstructing agent reacts with carbonate minerals, acid-soluble cements, or reactive ions in the formation to form sparingly soluble or slightly soluble mineral reconstruction products; the interface modifier adsorbs onto the surfaces of clay minerals, negatively charged particles, or the mineral-fluid interface, reducing the hydration dispersion and migration of clay particles and regulating the local crystallization environment; and the crystal morphology modifier adjusts the solution polarity and crystal growth environment, inhibiting the rapid aggregation of crystallization products into dense, massive precipitates and promoting the formation of needle-like, filamentous, or microcrystalline interwoven structures. Thus, the crystalline bridging components form a crystalline interpenetrating network at particle contact points, pore-throat boundaries, and clay-filled areas, enabling the weakly cemented particle system to form a reconstructed framework with localized support and continuous load-bearing capacity.

[0024] The film-forming protective component and the crystal bridging component work synergistically in terms of reaction time, reaction location, and product morphology. Upon contact with the surface of calcareous minerals, fracture walls, or acid-soluble cements, the film-forming protective component can rapidly undergo adsorption, complexation, or deposition, forming a protective film or surface stabilization layer on the framework surface. This stabilizes the mineral surface and pore throat boundaries, and provides interfacial conditions for subsequent crystallization product adhesion and growth. The crystal bridging component reacts and grows crystals relatively slowly, gradually forming needle-like or filamentous crystal networks at particle contact points, pore throat boundaries, and clay-filled areas, bridging, anchoring, and supporting weakly connected areas.

[0025] Through the synergistic effect of rapid film formation by the film-forming component and slow crystallization by the crystalline bridging component, the skeleton reconstruction process first stabilizes the skeleton surface and pore-throat boundaries, then enhances the load-bearing capacity of interparticle connections and weakly cemented areas. The film-forming protective component helps reduce particle surface peeling and clay dispersion during reconstruction, while the crystalline bridging component ensures that reconstruction products are distributed more extensively in weak areas of the skeleton and channel boundaries, rather than rapidly agglomerating and accumulating within the main seepage channels. Thus, the skeleton reconstruction fluid can improve formation skeleton stability while preserving as much effective seepage space as possible, providing a more stable pore-throat boundary and particle skeleton for subsequent main acid treatment.

[0026] Acid treatment based on framework reconstruction can achieve synergy between channel construction and framework stability. On the one hand, the main acid solution can dissolve near-wellbore plugging materials, acid-soluble filling materials, or residual carbonate components, forming acid-etched pore throats, wormholes, or acid-etched fractures, expanding effective seepage channels, and improving pore throat connectivity or fracture conductivity. On the other hand, the pre-formed film protection and crystallization bridging structure can provide a stable particle framework and pore throat boundaries for acid treatment, limiting particle shedding, mud dispersion, and channel wall collapse, reducing the risk of fine particle migration, pore throat blockage, and rapid decline in conductivity after acid treatment.

[0027] After the main acid treatment is completed, a post-treatment stabilizing and protective solution is applied to reinforce and protect the walls of acid-etched pores, wormholes, or acid-etched cracks. Clay stabilizers inhibit the hydration, expansion, dispersion, and migration of clay minerals; corrosion and scale inhibitors reduce the risk of continuous corrosion and sedimentation blockage caused by residual acid, formation water, and reaction products; and film-forming reinforcing agents form a reinforcing and protective layer on the walls of acid-etched channels, further improving the stability of the channels after acid treatment and the sustainability of the increased production effect.

[0028] Compared with the prior art, the present invention has the following beneficial effects: (1) A collaborative approach of skeleton reconstruction and acid treatment is proposed. For soft formations with low strength, weak cementation, and poor pore throat stability, single acid treatment or acid fracturing can easily weaken the skeleton strength and reduce post-acid channel stability, while single consolidation can easily cause pore throat blockage due to cementation product deposition. This invention reconstructs the skeleton before the main acid treatment to improve the formation skeleton's bearing capacity and pore throat boundary stability. Then, acid treatment forms acid-etched seepage channels, and post-treatment stabilization maintains channel stability, thereby reducing the risk of skeleton weakening from single acid treatment, avoiding pore throat blockage from single consolidation, and achieving stable production enhancement of soft formations. (2) A framework reconstruction mechanism of film-forming protection + crystallization bridging was constructed. The framework reconstruction described in this invention is different from conventional consolidation. Instead, it achieves framework stability through the synergistic effect of film-forming protection components and crystallization bridging components. The film-forming protection components form a protective film on the surface of calcareous minerals and fracture walls, improving surface hardness and acid corrosion resistance. The crystallization bridging components form needle-like crystalline interpenetrating structures at pore throat boundaries, particle contact points, and clay-filled areas, enhancing interparticle connections, anchoring clay and particles, and improving the formation framework bearing capacity and pore throat boundary stability. Attached Figure Description

[0029] Figure 1 A schematic diagram illustrating the synergistic mechanism of soft formation framework reconstruction and acid treatment; Figure 2 Comparison of macroscopic morphology of cores after separate acid treatment and framework reconstruction versus combined acid treatment; Figure 3 SEM image of the film-forming structure on the surface of the rock sample after treatment with skeleton reconstruction fluid; Figure 4 SEM image of the crystallization bridging structure of the rock sample after treatment with skeleton reconstruction fluid; Figure 5 Comparison of morphological features in experiments involving film formation protection of calcite rock blocks against acid corrosion. Detailed Implementation

[0030] The present invention will be further described below with reference to the accompanying drawings and specific embodiments to enable those skilled in the art to understand the invention. However, it should be understood that the present invention is not limited to the scope of the following specific embodiments. For those skilled in the art, any variations that fall within the spirit and scope of the invention as defined and determined by the appended claims are all within the scope of protection.

[0031] Example 1: Artificial mixed sedimentary rock cores were selected as the experimental subject; The core was formed by pressing calcite particles, clay minerals, and quartz sand, with a mass ratio of 6:1.5:2.5. The core diameter was 2.54 cm, the length was 8 cm, and the experimental temperature was 60℃. The effective pore volume PV of the core, measured by the vacuum saturation method, was 12.2 mL. The uniaxial compressive strength R of the core was... c It is 6.5 MPa, according to R c It was determined to be a soft stratum; Prepare the following working solution before the experiment: Standard displacement solution: 3wt% NH4Cl solution; Skeleton reconstruction solution: 10wt% film-forming protective component, 20wt% crystallization bridging component, 70wt% water; Film-forming protective components: 10wt% hydroxyethylidene diphosphonic acid, 10wt% sodium citrate, 2wt% sodium dodecyl sulfate, 78wt% water; Crystallization bridge components: 20wt% oxalic acid, 5wt% dodecyltrimethylammonium chloride, 3wt% ethanol, 72wt% water; Each 100g of the skeleton reconstruction solution consists of 10g of film-forming protective component, 20g of crystal bridging component, and 70g of water. Specifically, each 100g of the film-forming protective component consists of 10g of hydroxyethylidene diphosphonic acid, 10g of sodium citrate, 2g of sodium dodecyl sulfate, and 78g of water; each 100g of the crystal bridging component consists of 20g of oxalic acid, 5g of dodecyltrimethylammonium chloride, 3g of ethanol, and 72g of water. Main acid solution: 6wt% hydrochloric acid, 4wt% comprehensive additive, 90wt% water; the comprehensive additive consists of 40wt% oleic acid imidazoline, 30wt% Tween 80, and 30wt% ethanol; The main acid solution consists of 6g hydrochloric acid, 4g of comprehensive additives, and 90g water per 100g. The comprehensive additives consist of 40g oleic acid imidazoline, 30g Tween 80, and 30g ethanol per 100g. Post-stabilizing and maintaining solution: 1wt% potassium chloride, 0.5wt% hydroxyethylidene diphosphonic acid, 1wt% sodium silicate, 97.5wt% water; Each 100g of the post-stabilizing and maintaining solution consists of 1g of potassium chloride, 0.5g of hydroxyethylidene diphosphonic acid, 1g of sodium silicate, and 97.5g of water. Two sets of cores, A1 and A2, were used in the experiment. Before the experiment, the cores were placed in a core holder and heated to 60℃ and stabilized. During the experiment, a constant displacement rate of 1.0 mL / min was used, with the reference displacement solution as the permeability test solution. The A1 core was used to evaluate the effectiveness of direct bulk acid treatment. The experimental procedure is as follows: Step 1: Displace the core with 3wt% NH4Cl solution until the pressure differential stabilizes, and test the initial permeability K0; Step 2: Inject the main acid solution into the core, the injection volume being 2.0 times the effective pore volume PV of the core, i.e., 24.4 mL; Step 3: After the main acid solution is injected, it is replaced with 3wt% NH4Cl solution; Step 4: Observe the integrity of the core, the condition of the returned fluid particles, and the changes in pressure difference.

[0032] During the experiment, the A1 rock sample collapsed and showed obvious particle shedding, making it impossible to obtain a stable post-acid permeability.

[0033] A2 cores were used to evaluate the synergistic effect of skeleton reconstruction and acidizing treatment. The experimental procedure is as follows: Step 1: Displace the core with 3wt% NH4Cl solution until the pressure differential stabilizes, and test the initial permeability K0; Step 2: Inject the core with a skeleton reconstruction fluid at a volume of 1.0 times the effective pore volume PV of the core, i.e., 12.2 mL. Step 3: After injection, stop the displacement and keep the reaction at 60℃ for 24 hours; Step 4: Displace and drive the skeleton with 3wt% NH4Cl solution until the pressure difference stabilizes, and test the permeability K1 after skeleton reconstruction; Step 5: Inject the main acid solution into the core, the injection volume is 2.0 times the effective pore volume PV of the core, i.e. 24.4 mL; Step 6: Continue to inject post-stabilizing and maintaining fluid, the injection volume is 0.3 times the effective pore volume PV of the core, i.e. 3.7 mL; Step 7: Incubate the reaction at 60℃ for 12 hours; Step 8: Displace again with 3wt% NH4Cl solution until the pressure difference stabilizes, and test the permeability K2 after acid treatment.

[0034] The experimental results are shown in Table 1.

[0035] Table 1. Permeability variations and experimental phenomena under different core treatment methods. Table 1 shows that core A1, without framework reconstruction, collapsed after main acid treatment, exhibiting significant particle detachment, indicating that single acid treatment easily leads to framework instability in soft formations. Core A2, after synergistic treatment with framework reconstruction fluid, main acid solution, and post-treatment stabilization fluid, showed an increase in permeability from 68.08 mD to 103.62 mD, a permeability improvement ratio of 1.52, and no significant collapse occurred (see Table 1). Figure 2 This result demonstrates that the present invention can improve post-acid flow capacity while maintaining the stability of the soft formation framework.

[0036] Example 2: Bohai KL-16 mixed sedimentary rock sample was selected as the experimental object; The rock samples were taken from the target section of the KL-16 oilfield in the Bohai Sea. The lithology is mixed sedimentary rock with carbonate minerals, terrigenous clastic minerals, and argillaceous components. The rock samples contain well-developed calcareous cement and argillaceous infill, with weak grain cementation and poor pore throat boundary stability, belonging to typical mixed sedimentary soft strata rock samples. The same batch of Bohai KL-16 mixed sedimentary rock samples were processed into block samples and standard cylindrical samples. The block samples were used for surface Vickers hardness testing. Before the test, the test surface was polished to make it flat, clean, and free of obvious cracks and grains. No less than 5 test points were selected for each sample, and the average value was taken as the surface Vickers hardness.

[0037] Standard cylindrical specimens are used for uniaxial compressive strength testing. Before the test, the two ends of the specimen are ground flat and kept parallel. During the test, the specimen is loaded at a constant loading rate until it fails. The peak load is recorded and the uniaxial compressive strength is calculated. Prepare the following working solution before the experiment: Skeleton reconstruction solution: 10wt% film-forming protective component, 20wt% crystallization bridging component, 70wt% water; Film-forming protective components: 10wt% hydroxyethylidene diphosphonic acid, 10wt% sodium citrate, 2wt% sodium dodecyl sulfate, 78wt% water; Crystallization bridge components: 20wt% oxalic acid, 5wt% dodecyltrimethylammonium chloride, 3wt% ethanol, 72wt% water; Each 100g of the skeleton reconstruction solution consists of 10g of film-forming protective component, 20g of crystal bridging component, and 70g of water. Specifically, each 100g of the film-forming protective component consists of 10g of hydroxyethylidene diphosphonic acid, 10g of sodium citrate, 2g of sodium dodecyl sulfate, and 78g of water; each 100g of the crystal bridging component consists of 20g of oxalic acid, 5g of dodecyltrimethylammonium chloride, 3g of ethanol, and 72g of water. Main acid solution: 6wt% hydrochloric acid, 4wt% comprehensive additive, 90wt% water; the comprehensive additive consists of 40wt% oleic acid imidazoline, 30wt% Tween 80, and 30wt% ethanol; Post-stabilizing and maintaining solution: 1wt% potassium chloride, 0.5wt% hydroxyethylidene diphosphonic acid, 1wt% sodium silicate, 97.5wt% water; Each 100g of the post-stabilizing and maintaining solution consists of 1g of potassium chloride, 0.5g of hydroxyethylidene diphosphonic acid, 1g of sodium silicate, and 97.5g of water. Three groups of rock samples, D1, D2, and D3, were set up for the experiment. Before the experiment, the surface Vickers hardness and uniaxial compressive strength of each group of rock samples were tested as mechanical properties before treatment.

[0038] Group D1 was the skeleton reconstruction fluid treatment group. The experimental procedure is as follows: Step 1: Place the rock sample in a vacuum saturation device and evacuate it. Then inject the skeleton reconstruction fluid, so that the skeleton reconstruction fluid enters the pore throat of the rock sample under negative pressure until the rock sample is fully saturated with the skeleton reconstruction fluid. Step 2: Immerse the saturated rock sample in the framework reconstruction solution and react at a constant temperature of 60℃ for 24 hours; Step 3: After the reaction is complete, remove the rock sample and gently rinse the surface with deionized water to remove any residual liquid. Step 4: Dry the rock sample at 60℃ until its quality is basically stable; Step 5: Test the surface Vickers hardness and uniaxial compressive strength of the treated rock sample; Step 6: Take another representative rock sample cross section or surface small sample after treatment with the skeleton reconstruction solution and observe it under a scanning electron microscope to characterize the film structure, crystal morphology and bridging characteristics at the particle contact of the rock sample surface after skeleton reconstruction solution treatment.

[0039] Group D2 was the acid-treated group alone. The experimental procedure is as follows: Step 1: Place the rock sample in a vacuum saturation device and evacuate it. Then inject the main acid solution, so that the main acid solution enters the pore throat of the rock sample under negative pressure until the rock sample is fully saturated with the main acid solution. Step 2: Immerse the saturated rock sample in the main acid solution and react at 60°C for 2 hours; Step 3: After the reaction is complete, remove the rock sample and gently rinse the surface with deionized water to remove any residual liquid. Step 4: Dry the rock sample at 60℃ until its quality is basically stable; Step 5: Test the surface Vickers hardness and uniaxial compressive strength of the acid-treated rock sample.

[0040] Group D3 was the group receiving synergistic treatment of skeleton reconstruction and acid treatment. The experimental procedure is as follows: Step 1: Place the rock sample in a vacuum saturation device and evacuate it. Then inject the skeleton reconstruction fluid, so that the skeleton reconstruction fluid enters the pore throat of the rock sample under negative pressure until the rock sample is fully saturated with the skeleton reconstruction fluid. Step 2: Immerse the saturated rock sample in the framework reconstruction solution and react at a constant temperature of 60℃ for 24 hours; Step 3: After the reaction is complete, remove the rock sample, rinse the surface with deionized water to remove any residual liquid, and dry it at 60°C until the quality is basically stable. Step 4: Inject the main acid solution into the vacuum saturation device, so that the main acid solution enters the pore throat of the rock sample under negative pressure until the rock sample is fully saturated with the main acid solution; Step 5: Immerse the saturated rock sample in the main acid solution and react at 60°C for 2 hours; Step 6: After the main acid treatment is completed, the rock sample is placed in the vacuum saturation device again to draw a vacuum, and a post-stabilizing and preserving liquid is injected to allow it to enter the pore throat of the rock sample; then it is reacted at 60°C for 6 hours.

[0041] Step 7: After the reaction of the post-stabilizing and preserving solution is completed, take out the rock sample, rinse the surface with deionized water to remove any residual liquid, and dry it at 60°C until the quality is basically stable. Step 8: Test the surface Vickers hardness and uniaxial compressive strength of the rock samples after co-treatment.

[0042] The experimental results are shown in Table 2.

[0043] Table 2. Changes in mechanical properties of Bohai KL-16 mixed sedimentary rock samples before and after different treatment methods. As shown in Table 2, after treatment with the skeleton reconstruction fluid, the Vickers hardness of the rock sample increased from 53.8 HV to 115.6 HV, and the uniaxial compressive strength increased from 6.5 MPa to 10.6 MPa, indicating that the skeleton reconstruction fluid can improve the surface hardness and overall bearing capacity of the rock sample.

[0044] After acid treatment alone, the Vickers hardness of the rock sample decreased from 54.2 HV to 23.6 HV, and the uniaxial compressive strength decreased from 6.7 MPa to 2.8 MPa. This indicates that acid treatment alone weakens the calcareous cementation and pore throat boundary stability, resulting in a significant decrease in the mechanical properties of the rock sample.

[0045] After synergistic treatment of skeleton reconstruction and acid treatment, the Vickers hardness of the rock sample increased from 53.9 HV to 89.4 HV, and the uniaxial compressive strength increased from 6.6 MPa to 8.3 MPa, which is significantly better than the results of acid treatment alone. This indicates that the present invention can enhance the stability of the skeleton before acid treatment and maintain good surface strength and overall load-bearing capacity after acid treatment, achieving synergy between acid treatment and skeleton stability.

[0046] SEM observation of rock samples treated with framework reconstruction fluid revealed a relatively continuous film-like overburden on the surface of calcareous minerals. Needle-like or filamentous crystals were observed at grain contacts and pore throat boundaries. Some crystals formed interpenetrating, overlapping, and bridging structures between grains (see...). Figure 3 , Figure 4 This result indicates that the film-forming protective component in the skeleton reconstruction fluid can form a protective film or surface stabilization layer on the rock sample surface, and the crystal bridging component can form a crystal bridging network at weakly cemented sites, which explains the increase in surface Vickers hardness and uniaxial compressive strength from a microscopic perspective.

[0047] Example 3: Calcite rock blocks were selected as the experimental object.

[0048] The calcite rock blocks were used to simulate the surfaces of calcareous minerals and acid-soluble cementitious materials in soft strata. Before the experiment, the calcite rock blocks were cut into block samples, and the test surfaces were polished to make them flat, clean, and free of obvious cracks and grain loss. Then, they were dried until their quality was basically stable. Prepare the following working solution before the experiment: Film-forming protective solution: 10wt% hydroxyethylidene diphosphonic acid, 10wt% sodium citrate, 2wt% sodium dodecyl sulfate, 78wt% water; The film-forming protective solution consists of 10g of hydroxyethylidene diphosphonic acid, 10g of sodium citrate, 2g of sodium dodecyl sulfate, and 78g of water per 100g. Main acid solution: 3wt% hydrochloric acid, 3wt% comprehensive additive, 94wt% water; the comprehensive additive consists of 40wt% oleic acid imidazoline, 30wt% Tween 80, and 30wt% ethanol; The main acid solution consists of 3g hydrochloric acid, 3g of comprehensive additives, and 94g water per 100g. The comprehensive additives consist of 40g oleic acid imidazoline, 30g Tween 80, and 30g ethanol per 100g.

[0049] Step 1: Immerse the calcite rock block entirely in the film-forming protective solution and react for 2 hours to allow the film-forming protective solution to fully act on the surface of the calcite rock block and form a crystalline film or surface stabilization layer on the surface of the calcareous minerals. Step 2: Remove the rock block, lightly remove any residual liquid from the surface, and dry it until there is no obvious free liquid on the surface; Step 3: Lightly grind about half of the surface of the same rock block to remove the protective film layer on the surface of that area, forming a ground and removed film area; leave the other half unground, retaining the protective film layer, forming a film-protected area. Step 4: Place the treated calcite rock block in the main acid solution and react at room temperature for 10 minutes, so that the membrane protection area and the polishing and membrane removal area react simultaneously under the same acid solution conditions. Step 5: Observe the generation of bubbles, dissolution morphology, and grain shedding on the surfaces of the two regions during the reaction process; Step 6: After the reaction is complete, remove the rock block, rinse the surface with clean water to remove any residual acid, and observe the surface morphology of the rock block after drying.

[0050] The experimental results are shown in Table 3.

[0051] Table 3 Comparison of acid etching phenomena before and after film-forming protection on calcite rock blocks. As shown in Table 3, on the same calcite rock block, the polished area where the film was removed produced obvious bubbles after contact with the main acid solution, indicating strong surface dissolution and localized grain detachment; the film-protected area, under the same acid solution conditions, showed significantly fewer bubbles, reduced surface dissolution, and maintained a more intact overall morphology (see Table 3). Figure 5 This indicates that the film-forming protective solution can form a crystalline film on the surface of calcareous minerals, reducing the excessive dissolution of the mineral surface by the main acid solution, thereby improving the stability of the formation framework and the walls of the acid etching channels during acid treatment.

[0052] Example 4: The X1 well in the M oilfield was used as the implementation object.

[0053] The target formation is a mixed sedimentary rock formation. The midpoint depth H of the working section is 2200m, the length L of the working section is 80m, the formation temperature T is 75℃, the average formation pressure Pr is 18MPa, the average permeability K is 68mD, and the uniaxial compressive strength R... c It is 8.0 MPa. According to R... c The target formation is classified as a soft formation based on the criterion of ≤30MPa. According to the wellbore structure, work string parameters, logging interpretation, and target formation properties, the effective wellbore volume for pre-isolation is calculated to be 6.0 m³. 3 The pore volume of the modified well section is 40.0 m³. 3 The total displacement volume of the injection pipeline and injection string is 8.0 m³. 3 The target formation fracture pressure gradient αF is 0.0155 MPa / m, according to P f The target formation fracturing pressure P is calculated as αF·H. f The pressure was 34.1 MPa. Based on well logging interpretation and production dynamics analysis, the well mainly exhibited near-wellbore blockage and acid-soluble filling material blockage, and formation initiation was not required. Therefore, a synergistic production enhancement method combining framework reconstruction and matrix acidizing was adopted.

[0054] Prepare the following working solution before construction: Pre-isolation fluid: 3wt% NH4Cl solution.

[0055] Skeleton reconstruction solution: 12wt% film-forming protection component, 15wt% crystal bridging component, 73wt% water.

[0056] Film-forming protective components: 10wt% hydroxyethylidene diphosphonic acid, 10wt% sodium citrate, 2wt% sodium dodecyl sulfate, 78wt% water.

[0057] Crystallization bridge components: 30wt% oxalic acid, 5wt% dodecyltrimethylammonium chloride, 3wt% ethanol, 62wt% water.

[0058] Each 100g of the skeleton reconstruction solution consists of 12g of film-forming protective component, 15g of crystal bridging component, and 73g of water. Specifically, each 100g of the film-forming protective component consists of 10g of hydroxyethylidene diphosphonic acid, 10g of sodium citrate, 2g of sodium dodecyl sulfate, and 78g of water; the crystal bridging component consists of 30g of oxalic acid, 5g of dodecyltrimethylammonium chloride, 3g of ethanol, and 62g of water.

[0059] The main acid solution consists of 8 wt% hydrochloric acid, 4 wt% comprehensive additives, and 88 wt% water. The comprehensive additives are composed of 40 wt% imidazoline oleate, 30 wt% sodium dodecylbenzenesulfonate, and 30 wt% diethylene glycol butyl ether.

[0060] The main acid solution consists of 8g hydrochloric acid, 4g of comprehensive additives, and 88g water per 100g. The comprehensive additives consist of 40g imidazoline oleate, 30g sodium dodecylbenzenesulfonate, and 30g diethylene glycol butyl ether per 100g.

[0061] Post-stabilizing solution: 1wt% potassium chloride, 0.5wt% aminotrimethylphosphonic acid, 1wt% sodium silicate, 97.5wt% water.

[0062] Each 100g of the post-stabilizing and maintaining solution consists of 1g of potassium chloride, 0.5g of aminotrimethylphosphonic acid, 1g of sodium silicate, and 97.5g of water.

[0063] Displacement solution: 3wt% NH4Cl solution.

[0064] The construction process is as follows: Step 1: Inject pre-release fluid under pressure below 34.1 MPa, with a discharge rate of 1.5 m³. 3 The injection rate is 1 / min, and the injection volume is 1.2 times the effective wellbore volume, i.e., 7.2 m³. 3 ; Step 2: Inject the skeleton reconstruction fluid under conditions below 34.1 MPa, with a flow rate of 1.5 m³ / min. 3 The injection rate is 0.8 times the pore volume of the modified well section, i.e., 32.0 m³ / min. 3 ; Step 3: After the skeleton reconstruction fluid injection is completed, shut in the well for 12 hours; Step 4: Inject the main acid solution under conditions below 34.1 MPa, with a discharge rate of 2.0 m³ / min.3 / min, the injection volume is 2.0 times the pore volume of the modified well section, i.e., 80.0m³. 3 ; Step 5: Inject post-treatment stabilizing and retention fluid under pressure below 34.1 MPa, with a flow rate of 1.5 m³. 3 The injection rate is 0.3 times the pore volume of the modified well section, i.e., 12.0 m³ / min. 3 ; Step Six: Inject the displacement fluid at a flow rate of 1.0 m³. 3 The injection rate is 1 / min, and the injection volume is 1.3 times the volume that the injection pipeline and injection string need to displace, i.e., 10.4 m³. 3 ; Step 7: After the replacement is completed, shut the well in for 12 hours, then open the well for backflow.

[0065] The highest construction pressure during construction was 28.6 MPa, which is lower than the rupture pressure P. f =34.1MPa, no formation disintegration was observed. During the flowback process, no continuous large quantities of solid particles were observed being returned; the fine particle content in the flowback fluid gradually decreased, and the wellhead flowback pressure dropped steadily. Before construction, the well's daily fluid production was 18.5m³. 3 / d, daily oil production is 4.2m 3 / d, with significant fluctuations in production pressure differential. After modification using the synergistic production enhancement method of skeleton reconstruction and matrix acidification described in this invention, the daily liquid production increased to 52.6m³ in the initial stage of the modification. 3 / d, daily oil production increased to 12.8m 3 / d, the daily oil production increase ratio is approximately 3.0. After 90 days of continuous production, the daily oil production remains at 10.5m. 3 Above a certain rate (per day), no large number of continuous solid particles were observed in the produced fluid. This result indicates that the present invention can effectively clear near-wellbore blockages, improve post-acidification permeability, and maintain the stability of post-acidification pore-throat boundaries and formation framework.

Claims

1. A method for synergistically increasing production through soft formation framework reconstruction and acid treatment, characterized in that, Includes the following steps: (1) Collect target stratum data, based on uniaxial compressive strength R c Determine whether the target stratum is a soft stratum; (2) Calculate the target formation fracture pressure P f ; (3) The solution is injected in stages in the order of pre-isolation solution, skeleton reconstruction solution, main acid solution, post-stabilizing and maintaining solution, and displacement solution; the acid treatment method is selected from either matrix acidification or acid fracturing. (4) At a pressure below the rupture pressure P f Under the specified conditions, inject pre-placement fluid; the construction discharge rate is 0.5–3.0 m³. 3 / min, the injection fluid volume is 1.0 to 1.5 times the effective wellbore volume; (5) At a pressure below the rupture pressure P f Under the specified conditions, the skeleton reconstruction fluid is injected, with a construction flow rate of 0.5–3.0 m³. 3 / min, the injection volume is 0.5 to 1.5 times the pore volume of the modified well section; (6) Shutdown response: If the formation temperature T is higher than 120℃, shut down the well for 2 to 12 hours; if the formation temperature T is not higher than 120℃, shut down the well for 12 to 48 hours. (7) Inject the main acid solution, with two construction conditions: ① Synergistic production increase condition of skeleton reconstruction and matrix acidification: at a pressure lower than the rupture pressure P f Under the specified conditions, the main acid solution is injected at a discharge rate of 0.5–3.0 m³. 3 / min, the fluid volume is 1.0 to 3.0 times the pore volume of the modified well section; ② Synergistic production enhancement condition of skeleton reconstruction and acid fracturing: at a pressure higher than the fracturing pressure P f Under the conditions specified, the main acid solution is injected at a discharge rate of 2.0–8.0 m³. 3 / min, fluid volume is 2-6m per meter of working section. 3 Configuration; (8) At a pressure below the rupture pressure P f Under these conditions, inject post-treatment stabilizing and retention fluid; the discharge rate during construction is 0.5–3.0 m³. 3 / min, the injection fluid volume is 0.2 to 0.5 times the pore volume of the modified well section; (9) At a pressure below the rupture pressure P f Under these conditions, the displacement fluid is injected, with a discharge rate of 0.5–3.0 m³. 3 / min, the injection volume is 1.2 to 1.5 times the total displacement volume of the injection pipeline and injection string; (10) After the displacement fluid is injected, shut the well for 1 to 24 hours, then open the well for backflow.

2. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, With uniaxial compressive strength R c ≤30MPa is used as the criterion for determining soft formations.

3. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, The pre-isolation fluid is selected from one of the following: water, 1wt% to 5wt% KCl solution, and 1wt% to 5wt% NH4Cl solution.

4. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, The skeleton reconstruction solution is prepared by distributing the following mass fractions: 5wt% to 20wt% film-forming protective component, 5wt% to 20wt% crystallization bridging component, and the balance being water.

5. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 4, characterized in that, The film-forming protective component is prepared by distributing the following mass fractions: 5 wt%–30 wt% film-forming phosphonate, 5 wt%–30 wt% film-forming carboxylate, 1 wt%–10 wt% surfactant, with the balance being water; the film-forming phosphonate is one or more of aminotrimethylphosphonic acid, hydroxyethylidene diphosphonic acid, ethylenediaminetetramethylidene phosphonic acid, and sodium diethylenetriaminepentamethylidene phosphonate; the film-forming carboxylate is one or more of sodium citrate, sodium gluconate, sodium tartrate, sodium oxalate, sodium polyacrylate, and hydrolyzed polymaleic anhydride; the surfactant is one or more of sodium dodecylbenzenesulfonate, sodium dodecyl sulfate, dodecyltrimethylammonium chloride, hexadecyltrimethylammonium bromide, Tween 80, and cocamidopropyl betaine.

6. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 4, characterized in that, The crystal bridging component is prepared by distributing the following mass fractions: 10wt%–40wt% mineral remodeling agent, 1wt%–10wt% interface modifier, 1wt%–10wt% crystal morphology modifier, with the balance being water; the mineral remodeling agent is one or more of oxalic acid, sodium oxalate, ammonium oxalate, zinc chloride, zinc sulfate, sodium silicate, and sodium metasilicate; the interface modifier is one or more of dodecyltrimethylammonium chloride, tetradecyltrimethylammonium chloride, and hexadecyltrimethylammonium bromide; and the crystal morphology modifier is one or more of methanol, ethanol, isopropanol, ethylene glycol, and glycerol.

7. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, The main acid solution is prepared by distributing the following mass fractions: 3wt% to 15wt% acid solution, 3wt% to 5wt% comprehensive additives, and the balance being water; the acid solution is one or more of hydrochloric acid, formic acid, acetic acid, citric acid, oxalic acid, aminosulfonic acid, and ethylenediaminetetraacetic acid. The comprehensive additive is prepared by distributing the following mass fractions: 20wt%–60wt% corrosion inhibitor, 10wt%–40wt% surfactant, 10wt%–40wt% miscible solvent, with the balance being water; the corrosion inhibitor is one or more of hexamethylenetetramine, thiourea, propargyl alcohol, imidazoline oleate, dodecylpyridine chloride, hexadecylpyridine chloride, and dodecyltrimethylammonium chloride; the surfactant is one or more of sodium dodecylbenzenesulfonate, sodium dodecyl sulfate, dodecyltrimethylammonium chloride, hexadecyltrimethylammonium bromide, Tween 80, and cocamidopropyl betaine; the miscible solvent is one or more of diethylene glycol butyl ether, propylene glycol methyl ether, dipropylene glycol methyl ether, methanol, ethanol, and isopropanol.

8. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, The post-stabilizing and maintaining solution is prepared by dispensing the following components by weight: 0.5wt%–3wt% clay stabilizer, 0.1wt%–2wt% corrosion and scale inhibitor, 0.5wt%–5wt% film-forming reinforcing agent, with the balance being water; the clay stabilizer is one or more of potassium chloride, ammonium chloride, choline chloride, dodecyltrimethylammonium chloride, and cationic polyacrylamide; the corrosion and scale inhibitor is one or more of aminotrimethylphosphonic acid, hydroxyethylidene diphosphonic acid, hydrolyzed polymaleic anhydride, sodium polyacrylate, and oleic acid imidazoline; the film-forming reinforcing agent is one or more of sodium citrate, sodium gluconate, sodium oxalate, ammonium oxalate, sodium silicate, sodium metasilicate, zinc chloride, and zinc sulfate.

9. The method for synergistic production enhancement through soft formation framework reconstruction and acid treatment as described in claim 1, characterized in that, The displacement solution is selected from one of the following: 1wt% to 5wt% NH4Cl solution, 1wt% to 5wt% KCl solution, water, or formation water.

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