Retarded acid system for high temperature formation oil well exploitation and preparation method thereof

Abstract

The present application relates to oil and gas field development reservoir reconstruction technical field, specifically, it relates to a kind of slow acid system for high temperature stratum oil well exploitation, by weight percentage, the slow acid system is made of the following raw material components: hydrochloric acid: 15%-25%; Thickening agent: 0.5%-4.0%; High-temperature corrosion inhibitor: 3.0%-4.0%; Corrosion inhibitor synergist: 0%-2.0%; Iron ion stabilizer: 0.5%-1.5%; Assistant: 0.5%-1.5%; Clay stabilizer: 0.5%-1.5%; Gel breaker: 0.1%-2.0%; The rest is water;Wherein, the thickening agent is emulsion type supramolecular polymer.The emulsion type supramolecular polymer can effectively hinder the mass transfer diffusion of hydrogen ion to rock surface, ensure the feasibility of deep well large capacity construction, and ensure that acid liquid has very strong fracture width capacity and sand carrying capacity in fracture.

Description

Technical Field

[0001] This invention relates to the field of reservoir stimulation technology in oil and gas field development, and more specifically, to a slow-rate acid system for high-temperature formation oil well production and its preparation method. Background Technology

[0002] As oil and gas exploration and development advances into deeper and ultra-deeper layers, the burial depth of carbonate reservoirs (such as the Penglai gas area in the Sichuan Basin and the Tarim Basin) generally exceeds 6,000 meters, and even reaches over 8,000 meters. The reservoir temperature is often between 120℃ and 160℃, and even as high as 180℃. These reservoirs are typically characterized by strong heterogeneity, uneven development of fractures and vulnerabilities, and high temperature and pressure.

[0003] When performing acid fracturing on such reservoirs, existing acid systems react extremely rapidly with ordinary hydrochloric acid at high temperatures, causing the acid to be consumed near the wellbore, making it difficult to form deep-penetrating acid-etched fractures and effectively connect to distant reservoirs. To achieve deep penetration and wide fractures, it is usually necessary to increase the viscosity of the acid (such as cross-linked acid or gelling acid). However, high-viscosity acid exhibits enormous flow friction in wellbores thousands of meters long, severely limiting the fracturing rate and making it difficult to achieve high-volume fracturing.

[0004] Therefore, there is an urgent need to develop an intelligent acid system and its supporting processes that can withstand high temperature and high salinity environments, achieve low viscosity and drag reduction in the wellbore, high viscosity and slow formation, and support online real-time viscosity changes. Summary of the Invention

[0005] The purpose of this invention is to provide a slow-release acid system for high-temperature formation oil well production and its preparation method. By using a special emulsion-type supramolecular polymer as a thickener and combining it with an online continuous mixing process, the invention achieves efficient drag reduction in the wellbore and high-temperature viscosity enhancement and slow-release of the acid in the formation, thus resolving the contradiction between friction and slow-release in deep well acid pressure testing.

[0006] To achieve the above objectives, in one aspect, the present invention provides a slow-rate acid system for high-temperature formation oil well production, wherein the slow-rate acid system is composed of the following raw material components by weight percentage: Hydrochloric acid: 15%-25%; Thickener: 0.5%-4.0%; High-temperature corrosion inhibitor: 3.0%-4.0%; Corrosion inhibitor / synergist: 0%-2.0%; Iron ion stabilizer: 0.5%-1.5% Drainage aid: 0.5%-1.5%; Clay stabilizer: 0.5%-1.5%; Demolisher: 0.1%-2.0%; The remainder is water; The thickener is an emulsion-type supramolecular polymer, which is copolymerized from acrylamide monomers, sulfonic acid strong electrolyte monomers, cationic monomers containing a cyclic rigid backbone, and hydrophobic associating monomers.

[0007] The molar percentage of each polymeric monomer in the thickener is: Acrylamide monomers: 50%-75%; Sulfonic acid type strong electrolyte monomer: 20%-40%; Cationic monomers containing a cyclic rigid framework: 2%-10%; Hydrophobic associating monomers: 0.5%-3%; Wherein, the acrylamide monomer is acrylamide or methacrylamide; the sulfonic acid strong electrolyte monomer is 2-acrylamido-2-methylpropanesulfonic acid (AMPS) or its salt, the introduction of sterically hindered sulfonic acid groups significantly improves the stability of the polymer in a high-temperature acidic environment; the cationic monomer containing a cyclic rigid skeleton is dimethyl diallyl ammonium chloride (DMDAAC), the cyclic structure formed in the polymerization enhances the rigidity of the molecular chain and improves the shear resistance; the hydrophobic associating monomer is any one of N-dodecylacrylamide, N-hexadecylacrylamide or octadecyl methacrylate.

[0008] This invention also provides a method for preparing the thickener, employing a reverse emulsion polymerization method: acrylamide, AMPS, and DMDAAC are dissolved in water and the pH is adjusted to form an aqueous phase; a compound emulsifier (Span-80 and Tween-80 in a mass ratio of 2-4:1) is dissolved in diesel fuel to form an oil phase; after emulsification, a hydrophobic monomer is added, and polymerization is carried out under the action of an initiator to obtain an emulsion-type supramolecular polymer. The slow-release acid system is maintained at 120℃-160℃ and 170℃. After shearing for 60 minutes, the viscosity is ≥ Furthermore, the static acid-rock reaction rate at 90℃ is lower than... The dynamic corrosion rate of N80 steel sheets at 160℃ is less than 20%. .

[0009] A second aspect of the present invention provides a method for preparing the above-mentioned slow-release acid system, wherein the slow-release acid system is prepared using an online continuous mixing process, comprising the following steps: According to the weight percentages of each component as described in the claims, hydrochloric acid, high-temperature corrosion inhibitor, corrosion inhibitor synergist, iron ion stabilizer, drainage aid, clay stabilizer and water are mixed to prepare an acidic base solution. During the process of pumping the acidic base fluid into the wellbore, the thickener and breaker are directly injected into the flowing acidic base fluid pipeline using a metering pump for online mixing. The injection ratio of the thickener is adjusted in real time according to the construction pressure or formation depth requirements to prepare acid systems of different viscosities.

[0010] Specifically, in the low viscosity drag-reducing mode: the thickener injection ratio is 0.5%-1.5%, at which point the apparent viscosity of the slow-speed acid system is 9-15. It is used to reduce wellbore friction and connect natural fractures; In high-viscosity slow-release mode: the thickener injection ratio is 2.5%-4.0%, at which point the apparent viscosity of the slow-release acid system is 36-63. It is used to create the main joint and achieve deep penetration acid pressure.

[0011] Compared with the prior art, the beneficial effects of the present invention are as follows: 1. In the slow-release acid system and its preparation method for high-temperature formation oil well development, the thickener injection ratio can be adjusted in real time according to the bottom hole pressure response during construction, achieving seamless switching between low-viscosity drag-reducing fluid and high-viscosity fracture-creating acid, and accurately controlling fracture morphology (such as using viscous finger-propelled complex fractures); it saves a lot of surface mixing tank groups and waiting time for mixing, and the base fluid and main agent are pumped separately, avoiding the waste and disposal problems of the remaining prepared acid.

[0012] 2. In this slow-reduction acid system for high-temperature formation oil well development and its preparation method, by introducing heat-resistant sulfonic acid groups (AMPS) and a rigid cyclic framework (DMDAAC), the system of this invention can maintain stable rheological properties at temperatures of 160℃ or even higher, and exhibits high viscosity retention after 60 minutes of shearing. Simultaneously, with the addition of selected high-temperature corrosion inhibitors and synergists, the dynamic corrosion rate of N80 steel sheets is only 19.37 under high temperature and pressure at 160℃. This effectively solves the problem of tubing corrosion during acid fracturing construction in ultra-deep high-temperature wells.

[0013] 3. In the slow-release acid system for high-temperature formation oil well exploitation and its preparation method, the hydrophobic associative network structure of the emulsion-type supramolecular polymer thickener can effectively hinder the mass transfer and diffusion of hydrogen ions to the rock surface; under the same conditions (90℃, 6MPa), the static acid-rock reaction rate of the system of the present invention (high viscosity mode) is lower than that of the conventional gelled acid system, which can significantly slow down the acid-rock reaction process, allowing the active acid to penetrate deep into the far end of the formation and form longer and more effective acid etching fractures; Furthermore, under high-temperature and low-shear conditions in the formation (high-viscosity mode), as the temperature increases and the shear rate decreases, the viscosity of the system rapidly increases and stabilizes at 50. The above conditions (140℃ / 160℃) ensured the feasibility of large-volume deep well construction and also ensured that the acid solution had a strong ability to create fracture width and carry sand within the fracture. Attached Figure Description

[0014] Figure 1 This is a flowchart illustrating the overall process for preparing the slow-release acid system of the present invention. Detailed Implementation

[0015] The technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0016] To enable those skilled in the art to implement this invention, the preparation method of the key customized raw materials is first disclosed.

[0017] Raw material preparation example: Synthesis of thickener (emulsion-type supramolecular polymer) Step 1, Aqueous phase preparation: Weigh 180g of acrylamide (AM), 60g of 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and 10g of dimethyl diallyl ammonium chloride (DMDAAC), and dissolve them in 400g of deionized water; adjust the pH value to 7.0 with 20% NaOH solution to obtain the aqueous phase solution.

[0018] Step 2, oil phase preparation: Dissolve 15g of sorbitan monooleate (Span-80) and 5g of polyoxyethylene sorbitan monooleate (Tween-80) in 180g of white oil and mix well to form an oil phase.

[0019] Step 3, Emulsification and Polymerization: At a stirring speed of 1500 rpm, the aqueous phase was slowly added dropwise to the oil phase, emulsified for 30 min, and then deoxygenated by purging with high-purity nitrogen for 30 min. 2.5 g of N-hexadecylacrylamide (hydrophobic associating monomer) was added. The temperature was raised to 45℃, and 0.1 g of ammonium persulfate and 0.08 g of sodium bisulfite were added dropwise to initiate polymerization. The reaction was allowed to proceed for 4 h, yielding a milky white emulsion-type supramolecular polymer thickener with a solid content of approximately 35%. Its weight-average molecular weight was approximately [missing value]. .

[0020] Furthermore, the raw materials involved in this invention are: The high-temperature corrosion inhibitor is preferably a compound of Mannich base compounds, quaternary ammonium salt compounds and alcohols; the Mannich base compounds are prepared by condensation of acetophenone, formaldehyde and aniline under acidic conditions; The preferred corrosion inhibitor is one or a combination of antimony trioxide, antimony trichloride, potassium iodide, or cuprous chloride. The preferred iron ion stabilizer is one of citric acid, acetic acid, ethylenediaminetetraacetic acid (EDTA), or nitrotriacetic acid (NTA). The preferred drainage aid is one of the following: fluorocarbon surfactant, quaternary ammonium salt cationic surfactant, or polyether modified silicone oil; The clay stabilizer is preferably one of the following: polyquaternary ammonium salt (such as epichlorohydrin-dimethylamine copolymer), potassium chloride, or ammonium chloride; The preferred decapsulating agent is one of ammonium persulfate microcapsules, potassium persulfate microcapsules, or sodium bromate. Based on this, three acid solution system formulations were designed to meet different formation temperature requirements: 120℃, 140℃, and 160℃. Example 1: For a slow-rate acid system in a 120℃ formation, the formulation composition by mass percentage is as follows: Hydrochloric acid: 20%; Thickener (prepared according to the method of the raw material preparation example): 0.8% in low viscosity mode or 3.0% in high viscosity mode; High-temperature corrosion inhibitor: 3.0%; Iron ion stabilizer: 1.0% Drainage aid: 1.0%; Clay stabilizer: 1.0%; Demolisher: 1.0%; The remainder is water; Example 2: For a slow-rate acid system in a 140℃ formation, the formulation composition by mass percentage is as follows: Hydrochloric acid: 20%; Thickener (prepared according to the method of the raw material preparation example): 1.0% in low viscosity mode or 3.5% in high viscosity mode; High-temperature corrosion inhibitor: 3.0%; Corrosion inhibitor and synergist: 1.0%; Iron ion stabilizer: 1.0% Drainage aid: 1.0%; Clay stabilizer: 1.0%; Demolisher: 1.5%; The remainder is water.

[0021] Example 3: For a slow-rate acid system in a 160℃ formation, the formulation composition by mass percentage is as follows: Hydrochloric acid: 20%; Thickener (prepared according to the method of the raw material preparation example): 1.2% in low viscosity mode or 4.0% in high viscosity mode; High-temperature corrosion inhibitor: 4.0%; Corrosion inhibitor and synergist: 2.0%; Iron ion stabilizer: 1.0% Drainage aid: 1.0%; Clay stabilizer: 1.0%; Demolisher: 2.0%; The remainder is water.

[0022] Temperature resistance, shear strength, corrosion rate, and acid-rock reaction rate were tested on the high-viscosity slow-speed acid system (high-viscosity mode) configured in the above embodiments.

[0023] An RS6000 rheometer was used, with a shear rate of 170. The test duration was 60 min; the apparent viscosity and shear-retained viscosity of test examples 1-3 at different temperatures are shown in Table 1: Table 1: Viscosity and rheological properties test results of high-viscosity slow-release acid systems As shown in Table 1, the system of the present invention can still maintain a high viscosity under high temperature and high shear, which meets the requirements of deep acid fracturing for sand carrying and filtration loss control.

[0024] Dynamic corrosion experiments (16 MPa, 4 h) were conducted in a high-temperature and high-pressure autoclave using N80 and P110 steel sheets to verify the corrosion inhibition effect. Table 2: Viscosity and Rheological Properties Test Results of High-Viscosity Slow-Retardant Acid Systems As shown in Table 2, the high-viscosity, slow-repair acid system of this invention, when combined with a preferred high-temperature corrosion inhibitor and corrosion synergist, exhibits excellent high-temperature corrosion resistance. Even under extreme high-temperature conditions of 160°C, the average corrosion rate of N80 steel sheets is only 19.37%. This indicates that the system can effectively protect the wellbore string during long-term operations in high-temperature deep wells, meeting the needs of ultra-deep high-temperature reservoir stimulation.

[0025] To compare the performance of the present invention, the following comparative examples were designed: Comparative Example 1: The formulation of Example 2 was used, except that 1.0% of ordinary cationic polyacrylamide (without hydrophobic structure) was used instead of the emulsion-type supramolecular polymer thickener of the present invention, in order to compare the difference in retardation performance between ordinary thickener and supramolecular thickener of the present invention.

[0026] Comparative Example 2: A conventional autogenous acid system was used, with the following formulation: 8.0% methyl formate (acid-producing precursor), 10.0% ammonium chloride (activator), 3.0% high-temperature corrosion inhibitor, 1.0% drainage aid; balance is water. This is used to compare the drag-reducing performance and high-temperature crack-forming ability of existing low-viscosity acid solutions with the system of this invention.

[0027] Comparative Example 3: The high-viscosity formulation (containing 3.5% thickener) of Example 2 was used, but the difference was that the online mixing process was not used. Instead, the traditional construction method was simulated. All components were premixed and homogenized in a ground mixing tank at one time to form a high-viscosity acid solution, which was then directly pumped into the wellbore through the pumping equipment.

[0028] Based on the above comparative examples, a comparison of acid-rock reaction rates (retardation performance) was conducted. Under conditions of 90℃ and 6MPa, Example 2 and Comparative Example 1 were compared: Table 3: Comparison of acid-rock reaction rates As shown in Table 3, under the same viscosity (36 mPa·s) and experimental conditions, Example 2 using the emulsion-type supramolecular polymer thickener of the present invention exhibits an acid-rock reaction rate of 2.53 × 10⁻⁵. Compared to Comparative Example 1, which used ordinary cationic polyacrylamide, the reaction rate was reduced by approximately 56.2%. This confirms that the unique hydrophobic associative network structure of the thickener of this invention can effectively hinder the mass transfer and diffusion of H+ to the rock surface, significantly improving the retardation performance of the acid solution, which is beneficial for the active acid solution to penetrate deep into the formation and achieve deep penetration acid fracturing.

[0029] Based on the above comparative examples and on-site measurement data, Example 2 and Comparative Example 2 are compared: Table 4: Comparison of drag reduction rates As shown in Table 4, in the low viscosity drag reduction mode, the measured average drag reduction rate of Example 2 of the present invention reached 81%-83.2%, which is significantly higher than that of Comparative Example 2 (conventional self-generated acid / conventional acid system). This indicates that the supramolecular polymer molecular chains in the invention can more effectively expand and suppress the generation of turbulent vortices in the high shear flow field of the wellbore, thereby significantly reducing flow friction. This ultra-high drag reduction performance is a key technical guarantee for realizing large-volume pumping in deep wells (such as 8000m well depth) and reducing wellhead construction pressure.

[0030] Based on the above comparative examples, the ultimate capacity under actual 8000m deep well construction conditions was measured, and Example 2 was compared with Comparative Example 3: Table 5: Comparison of Construction Process Parameters As shown in Table 5, using the surface pre-mixing process of Comparative Example 3, the liquid already has a high viscosity (-100) before entering the well. This results in enormous wellbore friction, limiting the maximum operating flow rate to below 4.5 m³ / min, making it difficult to meet the needs of large-scale deep reservoir stimulation. However, this invention employs an online continuous mixing process (Example 2), maintaining the injected fluid at a low viscosity (-12). This significantly reduces friction along the flow path, allowing the maximum discharge rate to exceed 7.2 m³ / min under the same construction pressure. This process successfully resolves the conflict between high-viscosity acid and high-volume construction, greatly improving the flexibility of on-site operations and reducing the volume of modifications required.

[0031] Regarding Comparative Example 1: Test results show that the ordinary cationic polyacrylamide (without hydrophobic structure) used in Comparative Example 1 has poor stability under high temperature and high shear conditions. Although its initial viscosity meets the standard, under simulated high formation temperature (140℃) and shearing action, the molecular chains are prone to thermal degradation and mechanical breakage, resulting in low viscosity retention and the inability to form an effective spatial network structure to impede hydrogen ion migration. In contrast, the thickener of this invention introduces a rigid backbone and sulfonic acid groups, resulting in stronger temperature and shear resistance, and the hydrophobic association further enhances the retarding effect. Therefore, its retarding performance is significantly better than that of the ordinary polymer system.

[0032] Analysis of Comparative Example 2: Comparative data shows that although Comparative Example 2 (conventional authigenic acid system) can achieve low frictional resistance in some cases, it does not inherently possess viscosity-enhancing properties. The viscosity of the authigenic acid system remains at an extremely low level (typically <5%) after reacting in the formation. This results in a high acid filtration coefficient, making it difficult to support fractures or forming wide acid-etched fractures. However, the system of this invention (Example 2) possesses the intelligent characteristic of "one body, two states," achieving a drag reduction exceeding that of conventional systems in the wellbore (>80%), and transforming into a high-viscosity fluid (>50%) as the temperature rises after entering the formation. This effectively reduces filtration loss while creating gaps.

[0033] Regarding Comparative Example 3: Simulation calculations and field experience show that, using the pre-mixed surface process in Comparative Example 3, the high viscosity of the liquid entering the well (>100 mPa·s) causes a sharp increase in wellhead pump pressure, limiting the maximum discharge rate to 4.5 m³. 3 The flow rate is below / min. However, by employing the online mixing process of this invention, the fluid injected into the well is in a low-viscosity state, thereby increasing the discharge rate to 7.2m³ under the same pressure. 3 The speed of over / min significantly increased the volume of deep strata alteration.

[0034] Application example: Application in deep carbonate rock acid fracturing construction.

[0035] The well reached a total depth of approximately 8000m, with the target formation in section four and a reservoir temperature of 135℃. This well faced challenges including high well temperature, high fracture pressure, and high tubing friction. The online continuous mixing and real-time viscosity-changing process of this invention is used to pre-mix an acidic base liquid containing 20% ​​HCl and auxiliary agents such as corrosion inhibitors and iron stabilizers in a ground-based mixing tank; and then inject it in large volume using a clear oil pipe. Low viscosity and drag reduction stage: Inject 1.0%-1.5% thickener online as a pre-fluid and displacement fluid to reduce friction and connect natural microcracks; High-viscosity joint-forming stage: The proportion of thickener is increased to 3.5% online, which serves as the main acid. The high viscosity is used to form the main joint and carry the acid liquid for deep penetration. Construction parameters and effect data are shown in Table 6: According to Table 6, the construction pressure remained stable throughout the process, and the response to high and low viscosity switching was rapid; furthermore, post-pressure testing showed that the viscosity of the residual acid backflow solution was <5. The glue breaks completely, leaving no residue.

[0036] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely preferred examples and are not intended to limit the invention. Various changes and modifications can be made to the invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of the present invention as claimed. The scope of protection of the present invention is defined by the appended claims and their equivalents.

Claims

1. A slow-rate acid system for high-temperature formation oil well production, characterized in that, The slow-release acid system is composed of the following raw material components by weight percentage: Hydrochloric acid: 15%-25%; Thickener: 1.5%-4.0%; High-temperature corrosion inhibitor: 3.0%-4.0%; Corrosion inhibitor / synergist: 0%-2.0%; Iron ion stabilizer: 0.5%-1.5% Drainage aid: 0.5%-1.5%; Clay stabilizer: 0.5%-1.5%; Demolisher: 0.1%-2.0%; The remainder is water; The thickener is an emulsion-type supramolecular polymer, which is copolymerized from acrylamide monomers, sulfonic acid strong electrolyte monomers, cationic monomers containing a cyclic rigid backbone, and hydrophobic associating monomers.

2. The slow-rate acid system for high-temperature formation oil well development according to claim 1, characterized in that, The molar percentage of each polymeric monomer in the thickener is: Acrylamide monomers: 50%-75%; Sulfonic acid type strong electrolyte monomer: 20%-40%; Cationic monomers containing a cyclic rigid framework: 2%-10%; Hydrophobic associating monomers: 0.5%-3%; Wherein, the acrylamide monomer is acrylamide or methacrylamide; the sulfonic acid strong electrolyte monomer is 2-acrylamido-2-methylpropanesulfonic acid (AMPS) or its salt; The cationic monomer containing a cyclic rigid framework is dimethyl diallyl ammonium chloride (DMDAAC). The hydrophobic associating monomer is any one of N-dodecylacrylamide, N-hexadecylacrylamide, or octadecyl methacrylate.

3. The slow-rate acid system for high-temperature formation oil well development according to claim 2, characterized in that, The thickener is prepared by reverse emulsion polymerization, and its preparation method includes the following steps: Acrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and dimethyldiallylammonium chloride were dissolved in deionized water, and the pH was adjusted to 6-8 using an alkaline solution to form an aqueous phase. The compounded emulsifier is dissolved in diesel fuel to form an oil phase; The aqueous phase was added to the oil phase and mixed evenly under high-speed shearing. Nitrogen gas was introduced to remove oxygen, and then hydrophobic associating monomers were added. An initiator is added at 30-50°C to initiate the polymerization reaction, and the emulsion-type supramolecular polymer is obtained after 2-5 hours of reaction.

4. The slow-rate acid system for high-temperature formation oil well development according to claim 3, characterized in that, The compound emulsifier is composed of sorbitan monooleate and polyoxyethylene sorbitan monooleate in a mass ratio of 2-4:

1.

5. The slow-rate acid system for high-temperature formation oil well development according to claim 1, characterized in that, The slow-release acid system is formulated for a formation temperature of 120℃ as follows: 20% hydrochloric acid, 0.8%-3.0% thickener, 3.0% high-temperature corrosion inhibitor, 1.0% iron ion stabilizer, 1.0% drainage aid, 1.0% clay stabilizer, 1.0% breaker, and the balance is water.

6. The slow-rate acid system for high-temperature formation oil well development according to claim 1, characterized in that, The slow-release acid system is formulated for a formation temperature of 140℃ as follows: 20% hydrochloric acid, 1.0%-3.5% thickener, 3.0% high-temperature corrosion inhibitor, 1.0% corrosion inhibitor synergist, 1.0% iron ion stabilizer, 1.0% drainage aid, 1.0% clay stabilizer, 1.5% breaker, and the balance is water.

7. The slow-rate acid system for high-temperature formation oil well development according to claim 1, characterized in that, The slow-release acid system is formulated for a formation temperature of 160℃ as follows: 20% hydrochloric acid, 1.2%-4.0% thickener, 4.0% high-temperature corrosion inhibitor, 1.5%-2.0% corrosion inhibitor, 1.0% iron ion stabilizer, 1.0% drainage aid, 1.0% clay stabilizer, 2.0% breaker, and the balance is water.

8. The slow-rate acid system for high-temperature formation oil well production according to any one of claims 1-7, characterized in that, The slow-release acid system operates at 120℃-160℃, 170℃ After shearing for 60 minutes, the viscosity is ≥ .

9. A method for preparing a slow-return acid system for high-temperature formation oil well production as described in any one of claims 1 to 8, characterized in that, The online continuous mixing process includes the following steps: According to the weight percentage of each component as described in claim 1, hydrochloric acid, high-temperature corrosion inhibitor, corrosion inhibitor synergist, iron ion stabilizer, drainage aid, clay stabilizer and water are mixed to prepare an acidic base solution. During the process of pumping the acidic base fluid into the wellbore, the thickener and breaker are directly injected into the flowing acidic base fluid pipeline using a metering pump for online mixing. According to construction requirements, the injection ratio of the thickener is adjusted in real time to prepare acid systems of different viscosities.

10. The slow-rate acid system for high-temperature formation oil well development according to claim 9, characterized in that, The real-time adjustment includes a low-viscosity drag reduction mode and a high-viscosity slow-down mode; In the low viscosity drag-reducing mode, the thickener injection ratio is 0.5%-1.5%. In high viscosity slow-release mode: the thickener injection ratio is 2.5%-4.0%.

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