Anticorrosive paint for underground service casing and spraying construction method

Abstract

The invention relates to the technical field of oilfield chemistry, and particularly provides an anti-corrosion coating for an underground service casing and a spraying construction method, and the coating comprises the following components: 40-45wt% of a film-forming resin mixture; 5 to 8 wt% of surface modified nano composite particles; 1-3 wt% of a slow-release adhesion promoter; 0.5 to 2 wt% of a thixotropic agent; and the balance of a low VOC reactive diluent. The anticorrosive paint provided by the invention can be directly used for a casing pipe in underground service, has higher surface adhesion compared with a traditional pipeline anticorrosive paint, and can be tightly attached to the inner wall of the casing pipe; the corrosion resistance of high-salinity formation water is higher, the long-term stable service of the coating in an underground complex corrosion environment is effectively ensured, and the maintenance period of a casing pipe is greatly prolonged; the curing time is short, additional energy supply equipment is not needed for heating and curing, and energy waste and influence on related environment are avoided in cooperation with the low-VOC reactive diluent.

Description

Technical Field

[0001] This invention relates to the field of oilfield chemical technology, specifically providing an anti-corrosion coating for downhole casing and a spraying application method. Background Technology

[0002] Downhole casing is a steel tubing string that is run into the well in sections during petroleum engineering. Its outer wall is fixed with cement. Its main functions are to reinforce vulnerable formations, isolate underground layers with different pressures (such as aquifers and oil layers), prevent wellbore collapse, and provide a safe and stable passage for subsequent drilling and oil and gas production. It is a key component for ensuring drilling safety and the integrity of the wellbore structure.

[0003] In the process of oil and gas field development, downhole casing is often exposed to... , In complex environments with highly corrosive conditions, such as formation water with high mineralization, internal corrosion is a frequent problem. This corrosion can lead to casing perforation and leakage, and in severe cases, even force wells to be abandoned prematurely, causing huge economic losses to oil and gas field development.

[0004] The existing anti-corrosion coating process for casing can generally only be carried out during the casing manufacturing stage, specifically during pre-treatment work in the factory. For existing downhole casings that have already been in service, after the anti-corrosion coating wears off and fails, traditional secondary processing methods typically include composite coating technology, solvent-based epoxy recoating technology, and electroless nickel plating technology. Composite coating technology requires large-scale sandblasting equipment and open flame conditions; solvent-based epoxy recoating can be used on the outer wall of pipes but cannot be applied to downhole casings. Even if it could be used downhole, the process requires multiple, repeated applications, curing takes about 7 days, and the operation is risky, with the coating prone to blistering and peeling in the humid environment downhole; electroless nickel plating requires strict control of the plating solution's pH value, temperature, and other conditions, which are not feasible downhole. Therefore, current technologies generally only allow for the periodic addition of corrosion inhibitors to the downhole casing to extend its service life. Adding corrosion inhibitors can only delay the corrosion process of the casing in the short term, but cannot form a long-term anti-corrosion barrier on the inner wall of the casing. This makes it difficult to meet the requirements of wellbore integrity for long-term development of oil and gas fields, and will also generate huge material and construction costs during the long-term use of the casing.

[0005] Therefore, in order to ensure the service life of the casing and reduce construction costs, there is an urgent need for an anti-corrosion coating and spraying method that can perform secondary coating on the downhole casing that is already in service. Summary of the Invention

[0006] To address the aforementioned problems, this invention provides an anti-corrosion coating applicable to existing downhole casing, ensuring the casing's service life. The specific solution is as follows:

[0007] A corrosion-resistant coating for downhole casing, comprising: 40-45 wt% film-forming resin mixture; 5-8 wt% surface-modified nanomaterials. Composite particles; 1-3 wt% of slow-release adhesion promoter; 0.5-2 wt% of thixotropic agent; and the balance of low-VOC reactive diluent.

[0008] The anti-corrosion coating provided by this solution can be directly applied to casing in downhole service. Compared with traditional pipeline anti-corrosion coatings, it has higher surface adhesion and can tightly adhere to the inner wall of the casing; it is also more resistant to corrosion. , It exhibits superior corrosion resistance to high-mineralization formation water, effectively ensuring long-term stable service of the coating in complex downhole corrosive environments and significantly extending the casing maintenance cycle; with a short curing time, no additional energy supply equipment is required for heating and curing, and with the use of low-VOC active diluents, energy waste and related environmental impacts are avoided.

[0009] Preferably, the film-forming resin mixture is a mixed resin composed of dual-cured epoxy and vinyl ester, wherein the mass ratio of dual-cured epoxy to vinyl ester is 3:1 to 5:1.

[0010] In this scheme, the film-forming resin mixture serves as the base material for the coating. The combination of dual-curing epoxy and vinyl ester allows the base material to possess both the high adhesion of epoxy resin and the excellent chemical corrosion resistance of vinyl ester resin. It can form a stable cross-linked network structure in the downhole environment, providing the coating with good mechanical properties and a good anti-corrosion foundation.

[0011] Preferably, the The composite particles are surface modified using fluorosilanes.

[0012] In this scheme, the nano-coatings After the composite particles are modified with fluorosilane, hydrophobic groups are introduced onto the particle surface. The coating forms a dense hydrophobic barrier on its surface, effectively preventing corrosive media from penetrating into the coating and the coating-casing interface. At the same time, the high specific surface area of ​​the nanoparticles can form a "micromechanical interlocking" effect with the resin matrix, significantly improving the strength and wear resistance of the coating.

[0013] Preferably, the slow-release adhesion promoter contains phosphate groups.

[0014] In this scheme, the phosphate ester groups can react with the surface of the casing steel. A complexation reaction occurs, forming a stable "iron phosphate complex" that strengthens the chemical bond between the coating and the inner wall of the casing. The "slow-release" design allows it to slowly migrate to the coating-steel interface during long-term service. If the interfacial bond weakens due to localized medium penetration, the accelerator can replenish the complex in time, achieving dynamic reinforcement of the interfacial bond.

[0015] Preferably, the thixotropic agent is a compound of fumed silica and organobentonite, wherein the mass ratio of fumed silica to organobentonite is 2:1 to 4:1.

[0016] In this scheme, the thixotropic agent, which is a compound of fumed silica and organobentonite, can effectively regulate the rheological properties of the coating. Under static conditions, the coating maintains a high viscosity, preventing sedimentation and stratification of the coating in the storage tank and during the spraying process. When external force (such as pump pressure) is applied, the viscosity of the coating decreases, ensuring that it has good fluidity and is easy to atomize and spray through the nozzle.

[0017] Preferably, the low-VOC reactive diluent includes benzyl alcohol or dipropylene glycol methyl ether. The low-VOC reactive diluent is used to adjust the viscosity of the coating to meet the requirements of the spraying process, while reducing the volatile organic compound (VOC) content of the coating to meet environmental compliance standards.

[0018] In order to apply the above-mentioned coating to the inner surface of the in-service downhole casing, a method for spraying anti-corrosion coating for in-service downhole casing is provided. The method uses a spinning nozzle device that can install the above-mentioned anti-corrosion coating for in-service downhole casing. The spinning nozzle device is connected to the coiled tubing or drill pipe, and the spinning nozzle device rotates around the axis of the coiled tubing or drill pipe through a spinning mechanism.

[0019] In this scheme, the self-rotating nozzle device can rotate and move up and down along the casing axis via continuous tubing or drill pipe, and the anti-corrosion coating is sprayed in a fan shape, which can quickly and evenly spray the coating onto the inner wall of the downhole casing.

[0020] The preferred steps include:

[0021] S1. Remove the tubing and exposed well section, including the production tubing and existing packers and other downhole equipment, to completely expose the target casing section.

[0022] S2. Lowering the bridge plug and verifying the seal: Lower the retrievable bridge plug to the bottom of the target well section and test the sealing performance of the bridge plug by surface pressure testing. The pressure testing pressure must meet the specified standard, generally 20MPa.

[0023] S3. Drain the fluid, draining the accumulated fluid in the wellbore above the retrievable bridge plug.

[0024] S4. Well cleaning and pipe scraping: Use well cleaning and pipe scraping tools to perform well cleaning and pipe scraping operations on the target casing section.

[0025] S5. Spinning nozzle device: After the well cleaning and pipe scraping process is completed, the spinning nozzle device is lowered to the starting position above the retrieval bridge plug.

[0026] S6. Coating spraying: Drive the spinning nozzle device to rotate and spray out the anti-corrosion coating, while controlling the spinning nozzle device to slowly lift upward at a speed of 0.3–0.6 m / min.

[0027] S7. Natural curing: After spraying, keep all equipment stationary for 4–6 hours to allow the coating to cure naturally using the underground formation temperature.

[0028] S8. Wellbore restoration: After the coating has fully cured, remove the retrievable bridge plug to ensure unobstructed wellbore flow.

[0029] These steps form a standard construction method that relies entirely on conventional well workover procedures in oilfields. While ensuring construction safety, it eliminates the need for new large-scale specialized equipment. Operators can quickly master the construction essentials based on their existing well workover skills, reducing the difficulty and cost of technology promotion. Furthermore, this construction method enables the rapid and efficient application of anti-corrosion coatings to the casing in service downhole.

[0030] Preferably, in step S3, when draining the accumulated liquid, the liquid level in the wellbore should ultimately be at least 50 meters above the top of the section to be constructed.

[0031] In this step, before spraying, ensure that the accumulated liquid is below the bottom of the construction section, with a liquid depth of ≥50 meters. This allows the remaining liquid to form a safety cushion, effectively maintaining the pressure balance between the wellbore and the formation, and completely avoiding well kicks that could be caused by complete well depletion. Safety risks such as toxic gas release and casing deformation are fully compliant with oilfield well control safety regulations, providing a solid guarantee for the safety of on-site construction personnel and equipment.

[0032] The beneficial effects of this invention are:

[0033] 1. The anti-corrosion coating provided by this invention can be directly applied to casing in downhole service. Compared with traditional pipeline anti-corrosion coatings, it has higher surface adhesion and can tightly adhere to the inner wall of the casing; it is also more resistant to corrosion. , It exhibits superior corrosion resistance to high-mineralization formation water, effectively ensuring long-term stable service of the coating in complex downhole corrosive environments and significantly extending the casing maintenance cycle; with a short curing time, no additional energy supply equipment is required for heating and curing, and with the use of low-VOC active diluents, energy waste and related environmental impacts are avoided.

[0034] 2. The spraying construction method provided by this invention relies entirely on conventional well workover procedures in oilfields, ensuring construction safety without requiring additional large-scale specialized equipment. Operators can quickly master the construction essentials based on their existing well workover skills, reducing the difficulty and cost of technology promotion. Furthermore, this construction method can quickly and efficiently complete the anti-corrosion coating spraying construction of downhole casing. Attached Figure Description

[0035] To more clearly illustrate the technical solution of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0036] Figure 1 This is a schematic diagram of the process of the present invention. Detailed Implementation

[0037] The technical solution of the present invention will be clearly and completely described in conjunction with the accompanying drawings and through specific implementation methods of the embodiments of the present invention.

[0038] The anti-corrosion coating for downhole casing provided by this invention is composed of the following components: a film-forming resin mixture, surface-modified nanomaterials... Composite particles, slow-release adhesion promoter, thixotropic agent, and the remainder low-VOC reactive diluent.

[0039] It should be noted that slow-release adhesion promoters refer to those that are released under typical downhole conditions (such as temperatures of 30-120℃, pressures of 10-50MPa, and media containing...). / In high-mineralization formation water, adhesion promoters with a cumulative release period of ≥180 days for the active ingredients, and low-VOC reactive diluents refer to reactive diluents with a VOC content <50g / L. The mass fractions of each component in the anti-corrosion coating are based on the three core objectives of "performance balance, process adaptability, and downhole environment tolerance," and are the optimal ranges obtained through extensive experimental verification. Deviation from this range will lead to performance failure or construction failure.

[0040] Experiment 1: The film-forming resin mixture is a mixed resin composed of dual-curing epoxy and vinyl ester. As the matrix material of the coating, the mixture of dual-curing epoxy and vinyl ester allows the matrix material to possess both the high adhesion of epoxy resin and the excellent chemical corrosion resistance of vinyl ester resin. It can form a stable cross-linked network structure in the downhole environment, providing good mechanical properties and a good anti-corrosion foundation for the coating. The preferred mass ratio of dual-curing epoxy to vinyl ester in the dual-curing epoxy / vinyl ester mixed resin is 3:1 to 5:1, with a most preferred ratio of 4:1.

[0041] To verify the optimal mass fraction of the film-forming resin mixture, multiple comparative experiments were conducted: using the mass of the dual-curing epoxy:vinyl ester = 4:1 mixed resin as the variable, the surface-modified nanomaterials were compared with the mass fraction gradients of the film-forming resin mixture at 35wt%, 38wt%, 40wt%, 42wt%, 45wt%, 48wt%, 50wt%, and 55wt%. The coating samples were prepared by mixing 6 wt% composite particles, 2 wt% slow-release adhesion promoter, and 1 wt% thixotropic agent, with a low-VOC reactive diluent as a balance. The performance of each sample was then tested, and the results are shown in the table below.

[0042] Table 1. Effect of film-forming resin mixture content on coating performance

[0043]

[0044] As shown in the table above, the preferred mass of the dual-curing epoxy / vinyl ester mixed resin is between 40-55 wt%. The "corrosion resistance" of epoxy resin and the "weather resistance" of vinyl ester resin complement each other. At the same time, the mixing ratio of 40-55 wt% can balance the "crosslinking density" and "flexibility" of the coating: when it is below 40 wt%, the crosslinking is insufficient, and when it is above 55 wt%, the flexibility is too poor, which makes it easy to crack due to sleeve vibration.

[0045] Specifically, if the mass of the film-forming resin mixture is <40wt%, the film-forming resin mixture, as the matrix, will be unable to encapsulate the nanoparticles and accelerators, causing component stratification in the coating. Simultaneously, the mechanical properties of the cured coating will decrease (tensile strength <20MPa), leading to cracking. It will also reduce the bonding area with the steel surface of the inner wall of the casing, reducing adhesion to below 6MPa, failing to meet the requirements of in-situ spraying. Conversely, if the mass of the film-forming resin mixture is >55wt%, i.e., the content is too high, the coating viscosity will easily exceed 450mPa·s at room temperature (generally 25℃), thus preventing the coating from being atomized through the nozzle (spraying tools rely on 10-20MPa pump pressure for atomization; high viscosity easily clogs the nozzle). It will also lead to increased coating curing shrinkage (>3%), causing internal stress cracking; the nanoparticle concentration will be diluted, the density of the hydrophobic barrier will decrease, and corrosion resistance will weaken (HCl resistance time shortened to less than 15 days).

[0046] Experiment 2: Nanoparticles in Coating Components Composite particles undergo surface modification using fluorosilanes. Nanoparticles in coatings. After the composite particles are modified with fluorosilane, hydrophobic groups are introduced onto the particle surface. The nanoparticles form a dense hydrophobic barrier on the surface of the coating, effectively preventing corrosive downhole media from penetrating into the coating and the coating-casing interface. Simultaneously, the high specific surface area of ​​the nanoparticles allows them to form a "micromechanical interlocking" effect with the resin matrix, significantly improving the coating's strength and wear resistance. The core functions of the nanoparticles are "building a hydrophobic barrier" and "enhancing coating strength," and their mass fraction must match the encapsulation capacity of the resin matrix.

[0047] Therefore, in order to verify the optimal nano The mass fraction of composite particles was determined through multiple comparative experiments: [the experiment focused on] controlling only the nanoparticles. The performance of coatings prepared with varying composite particle mass fractions at 3wt%, 4wt%, 5wt%, 6wt%, 8wt%, 9wt%, 10wt%, and 12wt% were tested. The remaining components included a film-forming resin mixture with 48wt% added, a slow-release adhesion promoter with 2wt% added, a thixotropic agent with 1wt% added, and a low-VOC reactive diluent as a balance. The results of these coatings are shown in the table below.

[0048] Table 2 Nano The effect of composite particle content on coating performance

[0049]

[0050] As can be seen from the table above, nano If the mass of the composite particles is less than 5 wt%, the concentration of nanoparticles will be insufficient, which will affect the hydrophobic groups introduced after modification. Insufficient density results in a contact angle of less than 90° on the coating surface, preventing the formation of an effective hydrophobic barrier and allowing corrosive media to easily penetrate. It also weakens the "micromechanical interlocking" effect, reducing the coating's wear resistance (wear rate > 0.05 g / cm²), making it unable to withstand the friction during casing insertion. Nano If the mass of composite particles exceeds 8 wt%, the specific surface area of ​​the nanoparticles will be large, making them prone to agglomeration and resulting in pinhole defects in the coating. Similarly, it will cause the coating viscosity to abnormally increase to over 500 mPa·s, preventing the coating from meeting the requirements for spray flowability. Therefore, 5-8 wt% is suitable for nanoparticles. The optimal mass fraction range for composite particles.

[0051] Experiment 3: The slow-release adhesion promoter in the coating composition contains phosphate groups. These phosphate groups can undergo a complexation reaction with Fe²⁺ / Fe³⁺ on the casing steel surface to form a stable "iron phosphate complex," strengthening the chemical bond between the coating and the inner wall of the casing. The "slow-release" design allows it to slowly migrate to the coating-steel interface during long-term service. If the interfacial bond weakens due to localized medium penetration, the promoter can replenish the complex in time, achieving dynamic reinforcement of the interfacial adhesion. Therefore, the mass fraction needs to be controlled between "effective complexation" and "cost balance." To verify the optimal mass fraction of the slow-release adhesion promoter, multiple comparative experiments were conducted: only the mass fraction of the slow-release adhesion promoter was varied, and the coating performance was tested at mass fractions of 0.5wt%, 0.8wt%, 1wt%, 1.5wt%, 2wt%, 2.5wt%, 3wt%, and 4wt%. In the remaining components, 48wt% of surface-modified nano-polymers were added to the film-forming resin mixture. Each coating was prepared by mixing 6 wt% composite particles, 1 wt% thixotropic agent, and a low-VOC reactive diluent as a balance. Performance tests were conducted on the coating samples, and the results are shown in the table below.

[0052] Table 3. Effect of Slow-Release Adhesion Promoter Content on Coating Performance

[0053]

[0054] As shown in the table above, the optimal mass of the slow-release adhesion promoter containing phosphate ester groups is 1-3 wt%. Specifically, when the mass of the slow-release adhesion promoter containing phosphate ester groups is <1 wt%, the promoter is insufficient, resulting in a low amount of iron phosphate complex formation and an interfacial bonding force <7 MPa. Simultaneously, the "dynamic reinforcement" ability is weakened, causing the coating to be unable to withstand downhole pressure fluctuations for extended periods and prone to peeling. When the mass of the slow-release adhesion promoter containing phosphate ester groups is less than or greater than 3 wt%, the promoter is excessive, leading to high costs and the potential for unreacted phosphate ester groups to remain, creating "acidic sites" within the coating and accelerating resin aging and corrosion of the inner surface of the casing. Therefore, to verify the optimal mass fraction of the phosphate ester-containing slow-release adhesion promoter, multiple comparative experiments were conducted: only the mass fraction of the slow-release adhesion promoter was varied, and the coating performance was tested at mass fractions of 0.5 wt%, 0.8 wt%, 1 wt%, 1.5 wt%, 2 wt%, 2.5 wt%, 3 wt%, and 4 wt%. In the remaining components, 48 ​​wt% of surface-modified nano-polymers were added to the film-forming resin mixture. Each coating was prepared by mixing 6 wt% composite particles, 1 wt% thixotropic agent, and a low-VOC reactive diluent as a balance. Performance tests were conducted on the coating samples, and the results are shown in the table below.

[0055] Experiment 4: The thixotropic agent in the coating composition is a compound of fumed silica and organobentonite, wherein the mass ratio of fumed silica to organobentonite is 2:1 to 4:1, preferably 3:1. The thixotropic agent, a compound of fumed silica and organobentonite, can effectively regulate the rheological properties of the coating. Under static conditions, it maintains a high viscosity, preventing sedimentation and stratification during storage and spraying. When external force (such as pump pressure) is applied, the viscosity of the coating decreases, ensuring good flowability and facilitating atomization spraying through the nozzle. The core function of the thixotropic agent is "preventing sedimentation under static conditions and maintaining flowability during application," and its mass fraction must be precisely matched to the rheological requirements of the coating. Therefore, to verify the optimal thixotropic agent mass fraction, multiple sets of comparative experiments were conducted: only the thixotropic agent mass fraction was varied, and the coating performance was tested at mass fractions of 0.3wt%, 0.5wt%, 0.8wt%, 1wt%, 1.5wt%, 2wt%, 2.5wt%, and 3wt%. Among the remaining components, 48wt% of surface-modified nanomaterials were added to the film-forming resin mixture. Each coating was prepared by mixing 6 wt% composite particles, 2 wt% release adhesion promoter, and low-VOC reactive diluent as a balance. Performance tests were conducted on the coating samples, and the results are shown in the table below.

[0056] Table 4. Effect of thixotropic agent content on coating performance

[0057]

[0058] The table above shows that the optimal thixotropic agent content is 0.5-2 wt%. Specifically, when the thixotropic agent content is <0.5 wt%, insufficient thixotropic agent will cause "layering" (separation of nanoparticles and resin) when the coating is left to stand, resulting in uneven coating thickness after spraying. It may also cause coating "dripping" when spraying stops. When the thixotropic agent content is >2 wt%, excessive thixotropic agent will cause the coating viscosity to remain too high even under pump pressure, resulting in poor atomization and an "orange peel" texture on the coating. Similarly, the impact strength of the cured coating will be <5 kJ / m², making it susceptible to damage from downhole vibrations.

[0059] The reactive diluent in the coating components should be a low-VOC reactive diluent with a VOC content of <50g / L, preferably benzyl alcohol or dipropylene glycol methyl ether. Low-VOC reactive diluents are used to adjust the viscosity of the coating to meet the requirements of the spraying process, while simultaneously reducing the volatile organic compound (VOC) content of the coating to comply with environmental standards.

[0060] The anti-corrosion coating composed of the above-mentioned materials, with any appropriate ratio selected, has a viscosity of 300–450 mPa·s and a density of 1.15–1.25 g / cm³ at 25°C. When applied to slightly damp steel surfaces with relative humidity ≤85%, its adhesion remains ≥9 MPa after 7 days according to ASTM D4541 standard. When steel coated with this anti-corrosion coating is placed in a 15% HCl solution to simulate an underground environment of 90°C, no blistering is observed on its surface after 30 days.

[0061] The anti-corrosion coating provided by this invention can be directly applied to casing in downhole service. Compared with traditional pipeline anti-corrosion coatings, it has higher surface adhesion and can tightly adhere to the inner wall of the casing; it is also more resistant to corrosion. , It exhibits superior corrosion resistance to high-mineralization formation water, effectively ensuring long-term stable service of the coating in complex downhole corrosive environments and significantly extending the casing maintenance cycle; with a short curing time, no additional energy supply equipment is required for heating and curing, and with the use of low-VOC active diluents, energy waste and related environmental impacts are avoided.

[0062] Furthermore, in order to spray the above-mentioned coating onto the inner surface of the in-service downhole casing, a method for spraying anti-corrosion coating for in-service downhole casing is provided. This method uses a spinning nozzle device capable of installing the above-mentioned anti-corrosion coating for in-service downhole casing. The spinning nozzle device is connected to the coiled tubing or drill pipe, and the spinning nozzle device rotates around the axis of the coiled tubing or drill pipe via a spinning mechanism. This spinning nozzle device can be assembled using existing mechanisms, including a storage tank, a pressure-driven fan-shaped nozzle connected to the storage tank, a spinning mechanism, and a centralizer. Specifically, the storage tank has a volume of 5-10L and is pre-filled with nano-ceramic composite anti-corrosion coating. The storage tank's volume design can meet the construction needs of a single 30-70 meter well section (5.5-inch casing), reducing the number of tool trips during construction and improving construction efficiency. The pressure-driven fan-shaped nozzle relies on the pressure provided by the surface pump (10-20MPa) to connect to the storage tank and atomize the coating in the storage tank into uniform fan-shaped mist particles, ensuring that the coating can evenly cover the inner wall surface of the casing, forming a coating of consistent thickness. The pressure-driven fan-shaped nozzle is fixedly equipped with a spinning mechanism, which can use the fluid recoil force generated when the coating is sprayed to drive the tool to achieve circumferential rotation. The rotation speed is controlled at 5-15rpm, so that the coating sprayed from the nozzle forms a 360° coverage of the inner wall of the casing without dead angles. The pressure-driven fan-shaped nozzle connects to coiled tubing or drill pipe via a connector, enabling the connection between the tool and surface equipment. This provides support for the tool's lowering, lifting, and coating delivery. The connector can be replaced with a high-pressure injection connector to connect to surface delivery pipelines, enabling continuous material supply during long well runs. Of course, a centralizer should also be installed in the spinning nozzle system to ensure the tool remains centered on the casing during lowering and spraying, preventing collisions and wear between the tool and the casing's inner wall.

[0063] Furthermore, refer to Figure 1 The specific steps of the method for spraying anti-corrosion coating on downhole casing are as follows:

[0064] S1. Retrieve the tubing and exposed well section. Retrieve the production tubing and existing packers and other downhole equipment from the well, completely exposing the target casing section. During this step, the well workover operation must be strictly performed in accordance with the operating procedures to prevent damage to the tubing or secondary damage to the casing.

[0065] S2. Lowering and Sealing the Bridge Plug: Lower the retrieveable bridge plug to the bottom of the target well section and test its sealing performance by surface pressure testing. The pressure test must reach the specified standard (generally 20 MPa), and after a period of pressure stabilization, there should be no significant pressure drop, confirming the bridge plug's sealing is qualified. The bridge plug is used to temporarily seal the wellbore below the target well section, preventing paint leakage into the lower well section during construction, and simultaneously ensuring the drainage of accumulated fluid in the wellbore and pressure balance.

[0066] S3. Drainage: The accumulated fluid in the wellbore above the retrievable bridge plug is drained by reverse circulation or pumping.

[0067] In this step, before spraying, ensure that the accumulated liquid is below the bottom of the construction section, with a depth of ≥50 meters. This allows the remaining liquid to form a safety cushion, maintaining pressure balance between the wellbore and the formation, effectively preventing well kicks that may result from complete well depletion. This releases the risk of leakage from the casing while ensuring that the inner wall of the casing is not covered by free liquid and is only slightly damp, thus meeting the requirements for coating application.

[0068] S4. Well cleaning and casing scraping: Use well cleaning and casing scraping tools to perform well cleaning and casing scraping operations on the target casing section to remove rust, scale, oil and other impurities from the inner wall of the casing, exposing a fresh steel surface.

[0069] S5. The spinning nozzle device is lowered. After the well cleaning and pipe scraping process is completed, the spinning nozzle device is lowered to the starting position above the retrieval bridge plug.

[0070] S6. Coating spraying: Drive the spinning nozzle device to rotate and spray out the anti-corrosion coating, while controlling the spinning nozzle device to slowly lift upward at a speed of 0.3–0.6 m / min.

[0071] In this step, inert gas (such as nitrogen) or light oil is pumped in from the ground. The pressure of the gas or light oil forces the coating material in the storage tank into a pressure-driven fan-shaped nozzle, while the tool is slowly lifted at a speed of 0.3–0.6 m / min. Under the action of the ground pump pressure (10–20 MPa) and the spin mechanism, the coating material is atomized through the nozzle and evenly sprayed onto the inner wall of the casing, forming an anti-corrosion coating with a dry film thickness of 200–300 μm. This thickness range represents the optimal balance between "anti-corrosion effect" and "coating internal stress control," effectively blocking the penetration of corrosive media while avoiding internal stress cracking caused by curing shrinkage due to excessive coating thickness.

[0072] S7. Natural Curing: After spraying, keep all equipment stationary for 4–6 hours. Ensuring all tools remain stationary avoids scratching the wellbore and environmental disturbance. The entire process requires no additional heating devices, simplifying the tool structure. Utilizing the downhole formation temperature (typically 30–120℃, depending on well depth) enables natural curing of the coating, reducing energy consumption and construction risks. Simultaneously, the stability of the formation temperature ensures uniform curing, improving the coating's mechanical properties and corrosion resistance.

[0073] S8. Wellbore Restoration: After the coating has fully cured, remove the retrieveable bridge plug using drilling or retrieval methods to ensure wellbore patency. Restore the connectivity of the entire wellbore. Subsequently, clean and inspect the wellbore to confirm the absence of construction residue and wellbore patency before proceeding with subsequent operations such as running production tubing to restore normal oil well production.

[0074] These steps form a standard construction method that relies entirely on conventional well workover procedures in oilfields, such as tubing run-in, bridge plug sealing, and fluid pumping. This ensures construction safety without requiring the addition of large-scale specialized equipment. Operators can quickly master the construction techniques based on their existing well workover skills, reducing the difficulty and cost of technology promotion. Furthermore, this construction method enables the rapid and efficient application of anti-corrosion coatings to the casing in service downhole.

[0075] Example 1:

[0076] A certain onshore gas well has a casing specification of 139.7 mm (5.5 inches) and a well depth of 2800 m. Testing revealed that the producing formation contains 3% [unspecified substance]. 10% The formation water salinity reached 120,000 mg / L, and localized corrosion was observed on the inner wall of the casing at a depth of 2600–2700 m in the well section, requiring anti-corrosion repair work. The specific construction steps, following the methods provided in the above technical solution, are as follows:

[0077] Step 1: Following standard well workover procedures, remove the existing production tubing from the well to ensure the target casing section is unobstructed.

[0078] Step 2: Lower the retrieval bridge plug to a well depth of 2750m, pressurize it to 20MPa on the surface to test the seal of the bridge plug, and after stabilizing the pressure for 30 minutes, if the pressure does not drop, the bridge plug is confirmed to be qualified for sealing.

[0079] Step 3: Use pumping to drain the fluid accumulated in the wellbore above the bridge plug, monitor the fluid level in real time, and finally stabilize the fluid level at 2700m, retaining a 50-meter safety fluid cushion to meet the requirements of well control safety and coating construction.

[0080] Step 4: Use a well cleaning and scraping tool to clean and scrape the casing in the 2600–2700m section, removing rust, scale and other impurities from the inner wall of the casing. After completion, remove the scraping tool.

[0081] Step 5: Use a self-rotating nozzle device (equipped with an 8L storage tank pre-filled with anti-corrosion coating) to descend to a well depth of 2700m, above the bridge plug.

[0082] Step 6: Pump nitrogen into the coiled tubing using a ground pump unit, maintaining the pump pressure at 15 MPa, while simultaneously slowly raising the spraying tool at a speed of 0.5 m / min. Under the pressure of the nitrogen and the action of the spin mechanism, the coating is atomized through the nozzle and evenly sprayed onto the inner wall of the casing, forming an anti-corrosion coating with a dry film thickness of approximately 250 μm.

[0083] Step 7: After spraying, keep all equipment stationary and let it stand for 5 hours to allow the coating to cure naturally using the temperature of the underground formation, which is about 80°C.

[0084] Step 8: Use a drilling plug tool to drill and remove the retrieval bridge plug at a depth of 2750m. After retrieving the drilling plug tool and spraying tool, clean the wellbore, and then run in the production tubing to restore normal gas well production.

[0085] It should be noted that, in order to ensure continuous material supply and spraying, the length of a single construction well section is preferably 20–70 meters (depending on the capacity of the storage tank). When the length of the construction well section exceeds 70 meters, multiple sprayings can be carried out continuously. However, it is preferable to abandon the storage tank and directly replace the connector with a high-pressure injection connector, connect to the ground delivery pipeline, and supply the anti-corrosion coating to the self-rotating nozzle equipment from the ground to achieve continuous material supply and spraying of long well sections.

[0086] 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 illustrative of the principles of the invention. Various changes and modifications can be made to the present invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of protection claimed by the present invention.

Claims

1. An anti-corrosion coating for downhole casing, characterized in that, Based on the total mass of the coating, it consists of the following components: 40-45 wt% film-forming resin mixture; 5-8wt% surface-modified nanomaterials Composite particles; 1-3wt% of slow-release adhesion promoter; 0.5-2wt% thixotropic agent; and The remaining amount of low-VOC reactive diluent.

2. A corrosion-resistant coating for downhole casing as described in claim 1, characterized in that, The film-forming resin mixture is a mixed resin composed of dual-cured epoxy and vinyl ester, wherein the mass ratio of dual-cured epoxy to vinyl ester is 3:1 to 5:

1.

3. A corrosion-resistant coating for downhole casing as described in claim 1, characterized in that, The The composite particles are surface modified using fluorosilanes.

4. A corrosion-resistant coating for downhole casing as described in claim 1, characterized in that, The sustained-release adhesion promoter contains phosphate groups.

5. A corrosion-resistant coating for downhole casing as described in claim 1, characterized in that, The thixotropic agent is a compound of fumed silica and organobentonite, wherein the mass ratio of fumed silica to organobentonite is 2:1 to 4:

1.

6. A corrosion-resistant coating for downhole casing as described in claim 1, characterized in that, The low-VOC reactive diluent includes benzyl alcohol or dipropylene glycol methyl ether.

7. A method for spraying anti-corrosion coating on casing used in downhole operations, characterized in that, Using a spinning nozzle device loaded with the anti-corrosion coating for downhole casing as described in any one of claims 1 to 6, the spinning nozzle device is connected to coiled tubing or drill pipe, and the spinning nozzle device rotates around the axis of coiled tubing or drill pipe via a spinning mechanism.

8. The method for spraying anti-corrosion coating on downhole casing according to claim 7, characterized in that, Including steps: S1. Remove the tubing string and exposed well section, remove the production tubing and existing packers and other downhole equipment in the well, so that the target casing section is completely exposed. S2. Lowering the bridge plug and verifying the seal: Lower the retrieval bridge plug to the bottom of the target well section and test the sealing performance of the bridge plug by surface pressure testing, where the pressure testing pressure must meet the specified standard. S3. Draining fluid: Draining the accumulated fluid in the wellbore above the retrievable bridge plug; S4. Well cleaning and pipe scraping: Use well cleaning and pipe scraping tools to perform well cleaning and pipe scraping operations on the target casing section. S5. The spinning nozzle device is lowered. After the well cleaning and pipe scraping process is completed, the spinning nozzle device is lowered to the starting position above the retrieval bridge plug. S6. Coating spraying: Drive the spinning nozzle device to rotate and spray out anti-corrosion coating, while controlling the spinning nozzle device to slowly lift up at a speed of 0.3–0.6 m / min. S7. Natural curing: After spraying, keep all equipment stationary and let it stand for 4–6 hours to allow the coating to cure naturally using the underground formation temperature. S8. Wellbore restoration: After the coating has fully cured, remove the retrievable bridge plug to ensure unobstructed wellbore flow.

9. A method for spraying anti-corrosion coating on downhole casing according to claim 8, characterized in that, In step S3, when draining the accumulated fluid, the final liquid level in the wellbore should be at least 50 meters above the top of the section to be constructed.

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