A method of water plugging in a screen gravel packed self-priming well

Abstract

The present application relates to a kind of water plugging methods of screen gravel filling self-flowing oil well, including accurate identification water layer section by comprehensive well logging, production logging and numerical simulation data;Determine packer setting position based on well condition and indoor experiment;Design coiled tubing and tubing annulus injection temporary plugging agent temporary sealing upper oil production layer and gravel packing annulus, while injecting temporary plugging agent, coiled tubing injects certain viscosity preflush, prevent temporary plugging agent from entering bottom water production layer, prevent subsequent main blocking agent damage;Determine preflush viscosity according to reservoir permeability simulation sand filling pipe test.Determine main blocking agent injection time according to temporary plugging agent gel time, ensure that main blocking agent enters water production layer after gelation.Main blocking agent needs to have lower viscosity, to ensure that it enters water production layer first, and forms high-strength plugging barrier;Finally, release packer and induce flow.This application has achieved the beneficial effects: realize the deep precise plugging of water production layer, maximize the protection of oil production layer, effectively extend the self-flowing period of oil well and improve the recovery of crude oil.

Description

Technical Field

[0001] This invention relates to the technical field of water shut-off measures for self-flowing oil wells, and in particular to a water shut-off method for self-flowing oil wells filled with screened gravel. Background Technology

[0002] Loose sandstone oil and gas reservoirs are an important part of oil and gas resources in China and even the world, accounting for a significant proportion of the world's total oil reserves. These reservoirs have the advantages of good reservoir properties and high initial production capacity, and are the production cornerstone of many oil fields. However, loose sandstone reservoirs have low cementation strength and are prone to sand production during the production process. Therefore, sand control completion techniques such as screened gravel packing are often used to ensure wellbore stability.

[0003] The JK reservoir is characterized by relatively weak interlayer heterogeneity (small differences between layers), relatively low reservoir temperature (approximately 70℃), and extremely high formation water salinity (up to 24 × 10^4 mg / L). To address the sand production problem, the oilfield widely adopted the screened gravel packing completion method, and most wells were able to produce water automatically in the early stages of development. However, as development progressed, bottom and edge water, driven by the production pressure differential, easily advanced rapidly along high-permeability zones or dominant channels into the wellbore. Due to the high density of formation water (>1.16 g / cm³), when the water cut in the wellbore rose to a certain threshold, the weight of the liquid column increased significantly, causing the bottomhole flowing pressure to exceed the formation's supply capacity, thus causing the well to lose its automatic flow capability and be forced to stop production. Since the main producing layer is primarily a water-producing layer, the conversion pumping effect is not ideal. Currently, there is no mature supporting technology for precise water shut-off with gravel packing. Based on the identified defects and shortcomings, the inventors made further improvements to overcome the above problems. Summary of the Invention

[0004] The purpose of this invention is to overcome the shortcomings of the prior art and provide a water shut-off method for screen-tube gravel-filled self-flowing oil wells that can identify and seal water-producing sections, while effectively protecting the oil-producing layer from damage through the combination of packers and temporary plugging agents, thus solving the problem of sealing gravel-filled layers.

[0005] The objective of this invention is achieved through the following technical solution: a method for shutting off water in a self-flowing oil well filled with screened gravel, comprising the following steps: S1: Water-producing layer identification: Based on the logging data of the target well and the oil saturation data determined by numerical simulation or the production logging data of adjacent wells, the main water-producing layer is determined comprehensively. S2: Determining the setting position of the packer: Based on the cementing quality logging data, the longitudinal distance between the water-producing layer and the oil-producing layer, and the longitudinal migration distance of the temporary plugging agent in the gravel-filled annulus determined by the sand-filled pipe simulation experiment, the setting position of the packer is determined. S3: Design and construction of temporary plugging agent injection: (3a) Design of temporary plugging agent dosage: Through parallel sand-filled pipe experiments, the permeability of the oil-producing layer and the permeability of the gravel-filled annulus were simulated respectively. The depth of the temporary plugging agent entering the oil-producing layer and the longitudinal migration height in the gravel-filled annulus were measured. Based on this, the total volume of the temporary plugging agent required was calculated. (3b) Injection construction: The temporary plugging agent is injected through the annulus between the coiled tubing and the production tubing using a pump truck, so as to seal the oil-producing well section above the packer at the location and the adjacent gravel-filled annulus. S4: Design and construction of main plugging agent injection: (4a) Design of main plugging agent dosage: Based on the permeability of the water-producing layer, the formation pressure gradient of the main plugging agent is determined by the sand-filled pipe experiment; the production pressure difference under the optimal daily production rate is determined according to the reservoir numerical simulation; and the plugging radius and dosage of the main plugging agent are calculated to ensure that the plugging strength is greater than the production pressure difference. (4b) Injection construction: The main plugging agent is pumped into the water-bearing section through a coiled tubing using a pump truck and then displaced from the coiled tubing; S5: Packer release and tubing lifting: After the main plugging agent has cured to the predetermined strength, release the packer and lift it to a safe position; S6: Well Opening Induced Flow: Well opening for production. If it cannot flow on its own, nitrogen gas lift will be used to induce flow.

[0006] As a preferred technical solution of this application, the viscosity of the temporary plugging agent used in step S3 is 500 mPa·s to 1000 mPa·s at the reservoir temperature.

[0007] As a preferred technical solution of this application, the viscosity of the main plugging agent used in step S4 is 0 mPa·s to 200 mPa·s at the reservoir temperature.

[0008] As a preferred technical solution of this application, in step S3, after the temporary plugging agent is injected, a temporary plugging agent plug with a certain height is formed in the gravel-filled annulus above the packer. This plug can effectively prevent the subsequent main plugging agent from migrating infinitely in the longitudinal direction, thereby achieving efficient separation of the wellbore and the reservoir.

[0009] As a preferred technical solution of this application, the step S2 of determining the setting position of the packer specifically includes: S21. Select a suitable well section as a candidate setting location; S22. Conduct a sand-filled pipe simulation experiment: Establish a parallel sand-filled pipe model, with one pipe simulating the permeability K2 of the oil-producing layer and the other pipe simulating the permeability K1 of the gravel-filled annulus; inject a temporary plugging agent and record the injection pressure P1 when it enters a certain depth of the simulated oil-producing layer, as well as the longitudinal migration height h1 of the temporary plugging agent in the simulated gravel-filled pipe under the pressure P1, which is the deepest position of the packer setting position from the top of the water-producing layer; S23. Calculate the safety distance: Use the experimentally measured h1 as the expected longitudinal migration distance of the temporary plugging agent in the actual gravel-filled annulus downhole; S24. Determine the setting depth: The setting depth of the packer should ensure that the vertical distance between its lower end face and the top boundary of the outlet layer is not less than h1, and should preferably be selected within the candidate setting position range determined in S21.

[0010] As a preferred technical solution of this application, the design of the amount of temporary plugging agent used in step S3 is as follows: Based on the depth L0 of the temporary plugging agent entering the simulated oil-producing layer determined by the sand-filled pipe experiment, the volume of the temporary plugging agent entering the actual oil-producing layer is calculated using the cylinder formula: V1 = π * (R1^2 - R2^2) * L0, where R1 is the wellbore radius and R2 is the outer radius of the screen pipe. Based on the longitudinal transport height h of the temporary plugging agent in the simulated gravel-filled annulus determined by the sand-filled pipe experiment, calculate the volume of the temporary plugging agent occupying the gravel-filled annulus: V2 = π * [(R1^2 - R3^2) - (R2^2 - R3^2)] * h1, where R3 is the inner radius of the sieve tube. The total amount of temporary plugging agent used, Vtotal, is equal to V1 plus V2.

[0011] As a preferred technical solution of this application, the design of the main plugging agent dosage in step S4 is as follows: The pressure gradient p of the main plugging agent under simulated effluent permeability conditions was determined through sand-filled pipe experiments. By using reservoir numerical simulation, the bottom hole flowing pressure of the oil well under the optimal daily fluid production rate Q after water control is determined, and then the production pressure difference ΔP between the well and the formation pressure is calculated. The sealing strength of the main plugging agent is designed as S = n * ΔP, where n is the safety factor, which takes a value greater than 1; Calculate the sealing radius of the main plugging agent: R = S / p; The amount of main plugging agent V3 is calculated according to the cylinder formula: V3 = π*φ * (R^2 - R1^2) * h2, where φ is the porosity of the effluent layer and h2 is the effective thickness of the effluent layer.

[0012] As a preferred technical solution of this application, the water-producing layer identification in step S1 is as follows: when production logging data is available, the main water-producing layer is determined directly based on the water production contribution of each layer; when production logging data is not available, the water-producing layer information of adjacent wells and the logging interpretation results of this well are combined, and numerical simulation technology is used for inversion or a comprehensive judgment is made through the distribution law of permeability and oil saturation.

[0013] The present invention has the following advantages: (1) Achieve precise water plugging while avoiding damage to the oil layer; This solution uses a packer and a temporary plugging agent to physically isolate the oil-producing layer during construction and ensure that the subsequent main plugging agent only acts on the target water-producing layer. This completely avoids the problem of conventional chemical plugging agents damaging the oil-producing layer and maximizes the recovery of oil well productivity. (2) Effectively solves the problem of plugging gravel-filled wells; The temporary plugging agent used in this solution works in conjunction with the packer in the gravel-filled annulus to effectively block the channel through which bottom water flows vertically upward through the high-permeability gravel annulus. This technique is superior to the existing mechanical plugging technology, as it can seal the gravel-filled portion and prevent the bottom water-exit layer from flowing out. (3) The dosage of the plugging agent is precise and the effect is good; This scheme, based on the dosage design method of sand-filled pipe experiments and reservoir simulation, ensures that the dosage of the main plugging agent is just enough to form an effective sealing barrier, thereby avoiding waste of plugging agent and damage to the deep water-producing layer caused by excessive injection. The water-blocking method in this scheme can accurately seal the water-producing layer, prolong the self-flowing period of the oil well, and thus increase crude oil production. Attached Figure Description

[0014] Figure 1 A schematic diagram of a water shut-off method for a self-flowing oil well filled with screened gravel, provided by the present invention. Detailed Implementation

[0015] The present invention will be further described below with reference to the accompanying drawings, but the scope of protection of the present invention is not limited to the following description.

[0016] It should be noted that the orientation or positional relationship indicated by terms such as "left" and "right" is based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship in which the product of the invention is usually placed during use, or the orientation or positional relationship in which those skilled in the art would conventionally understand it. Such terms are only for the convenience of describing the invention and simplifying the description, and are not intended to indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the invention.

[0017] It should be noted that, unless otherwise specified, the embodiments and features and technical solutions in the present invention can be combined with each other.

[0018] Therefore, based on the above problems, this invention proposes a water shut-off method for screened gravel-filled self-flowing oil wells.

[0019] This implementation plan proposes a water shut-off method for a screened gravel-filled self-flowing oil well. The method primarily involves inserting a packer into the well and establishing a temporary setting point downhole. Then, a temporary plugging agent is injected to temporarily seal the oil-producing layer above the packer and the adjacent gravel annulus. Subsequently, the main plugging agent is precisely injected into the water-producing layer below the packer through coiled tubing for high-intensity sealing. Finally, the packer is released and lifted (i.e., the temporary sealing is released), thereby restoring production. The water shut-off method in this implementation plan includes the following steps: Preferably, in step S1, the water outlet layer is first identified and determined; accurate location of the water outlet layer is a prerequisite for successful water blocking, and this invention uses various data for determination: When PLT test data is available, production logging can directly provide the flow rate of each section under production conditions. By analyzing this PLT data, the sections with water production much greater than oil production can be clearly identified, which are the main water-producing layers. When PLT test data is unavailable, a comprehensive judgment is made by using oil saturation and permeability profiles obtained from conventional logging data, combined with reservoir numerical simulation technology. First, by referring to the PLT or water-producing layer information of neighboring wells with similar geological characteristics and similar production stages, the possible water-producing intervals of this well are inferred. Second, using the logging interpretation results of this well, a reservoir numerical model is established or modified, and by fitting historical production data, water channeling channels and main water-producing layers are inverted. In addition, for reservoirs with small interlayer differences, high-permeability layers are often the dominant channels for water channeling, so intervals with abnormally high permeability need to be observed.

[0020] It should be noted that PLT refers to Production Logging Test, which mainly measures parameters such as flow rate, pressure, and temperature of fluids in the wellbore during normal production or injection to assess the production and intake of each production layer. In this scheme, PLT test data is crucial for determining the water-producing layer. A single measurement can obtain the fluid profile along the entire perforated section (i.e., the oil-producing and water-producing layers in this scheme). Furthermore, by analyzing the PLT curve, it is possible to visually identify which depth segment has an abnormally high water content and a large production volume in the fluid. This segment can be directly identified as the main water-producing layer, thus obtaining the precise location of the water-producing layer, which is the basis for determining the packer setting position and calculating the temporary and main plugging agents in subsequent steps.

[0021] Preferably, in step S2, the packer setting position is determined. First, the packer setting position is preferably in a well section with good cementing quality. At the same time, since the temporary plugging agent will also move longitudinally along the gravel packing into the water-producing layer while entering the oil layer, the permeability K1 of the gravel packing and the permeability K2 of the oil-producing layer are referenced. Based on the depth of the temporary plugging agent entering the oil-producing layer, and through the sand-filled pipe experiment, the longitudinal migration distance of the temporary plugging agent can be determined, which is the deepest position h1 of the packer setting position from the top of the water-producing layer (that is, the lower end face of the packer must be greater than or equal to the experimentally measured safe longitudinal migration distance h1 of the temporary plugging agent to ensure that the temporary plugging agent will not contact or invade the water-producing layer). Furthermore, the packer is inserted into the well using the ball-dropping pressure setting principle, and a surface setting simulation is performed before insertion to ensure safe setting inside the wellbore; at the same time, water absorption is measured and a simulated wellbore passage and bottom exploration are performed before the packer is inserted into the well.

[0022] Preferably, in step S3, the dosage of the temporary plugging agent is designed and calculated. The temporary plugging agent selected in this scheme has a viscosity of 500 mPa·s to 1000 mPa·s at reservoir temperature. A pump truck is used to inject the temporary plugging agent through coiled tubing and the tubing annulus. The temporary plugging agent seals the upper oil-producing section of the packer. It should be noted that when this temporary plugging agent is prepared and pumped on the surface (surface temperature <40℃), its viscosity is ~100mPa·s, making it easy to pump. After entering the wellbore and being heated (reaching 70℃), the viscosity rapidly increases within 30 minutes and stabilizes at 750mPa·s (within the 500-1000 mPa·s range required for temporary plugging agents). This high viscosity gives it extremely strong structural strength and retention capacity.

[0023] Meanwhile, the temporary plugging agent contains a certain amount of hydrophobic modifier, which enables it to selectively enter and retain formations with high oil saturation, thus making it more conducive to forming effective plugging in oil-producing layers.

[0024] This scheme precisely calculates the amount of temporary plugging agent used: First, based on the sand-filled pipe experiment and using parallel sand-filled pipes, one is used to simulate the permeability of the oil-producing layer to obtain data K2, and the other is used to simulate the permeability of gravel filling to obtain data K1; then, based on the depth L0 of the temporary plugging agent entering the simulated oil-producing layer determined by the sand-filled pipe experiment, the volume V1 of the temporary plugging agent entering the oil-producing layer is calculated according to the cylinder calculation formula, where V1 is π* (R1^2 - R2^2) * L0, where R1 is the wellbore radius and R2 is the outer radius of the screen pipe; Simultaneously, based on the longitudinal transport height h of the temporary plugging agent in the simulated gravel-filled annulus determined by the sand-filled pipe experiment, the volume of the temporary plugging agent occupying the gravel-filled annulus is calculated as V2 =π* [(R1^2 - R3^2) - (R2^2 - R3^2)] * h1, where R3 is the inner radius of the sieve tube; Therefore, the total amount of temporary plugging agent used in this scheme, Vtotal, is calculated as V1 + V2.

[0025] It should be noted that the temporary plugging agent injection process in this plan is as follows: First, well cleaning and tubing string preparation are carried out; the well is run down to below the predetermined setting depth to ensure that the wellbore is unobstructed, and then the construction tubing string with a retrievable compressible packer (the model can be selected according to the pressure) is run in, and the packer is connected to the tubing; Next, the packer is set; a setting ball is inserted into the tubing, and after the ball is in place, the tubing is pressurized by a pump truck, the packer sleeve expands and anchors, and is firmly set on the casing.

[0026] Connect the injection equipment; connect the pump truck and coiled tubing truck on the ground, and lower the coiled tubing through the wellhead blowout preventer, with its lower outlet located a certain distance above the packer.

[0027] Finally, the temporary plugging agent was pumped in; the pump truck was started, and the temporary plugging agent solution was pumped in through the annulus between the coiled tubing and the tubing (i.e., the tubing-casing annulus). During the pumping process, the wellhead pressure slowly rose from 0 and eventually stabilized, and the pressure curve was smooth without abnormal fluctuations, indicating that the injection was successful.

[0028] After pumping is completed, the well is immediately shut in; the temporary plugging agent in the wellbore is allowed to statically gel and thicken at a formation temperature of 70°C; at this time, the high-viscosity temporary plugging agent has effectively sealed all the perforation holes / screen gaps of the oil-producing layer above the packer, and extends downward a certain distance in the gravel annulus outside the screen to form a stable "temporary barrier".

[0029] Preferably, in step S4, the amount of the main plugging agent is designed and calculated. The viscosity of the main plugging agent used in this scheme is 0 mPa·s to 200 mPa·s at the reservoir temperature. The main plugging agent is introduced into the water-bearing layer through a continuous tubing using a pump truck for plugging.

[0030] It should be noted that after the main plugging agent is mixed on the surface, the initial viscosity is only 80 mPa·s (which is within the 0-200 mPa·s range required by the main plugging agent). It has excellent injectability and deep formation penetration ability, which can ensure that it enters the deep water-producing layer rather than just sealing the well wall. It is not sensitive to high-salinity formation water and has stable performance.

[0031] This scheme precisely calculates the dosage of the main plugging agent: First, based on the permeability of the water-producing layer and using the same sand-filled pipe experiment, the pressure gradient p of the main plugging agent under the simulated permeability of the water-producing layer is determined; then, based on the numerical simulation of the optimal daily production rate Q, the bottom hole flowing pressure under the optimal daily production rate Q after water control is calculated, and then the production pressure difference ΔP between the production pressure and the formation pressure is calculated.

[0032] Furthermore, to ensure long-term effectiveness of the sealing and to prevent changes in production pressure differentials, the strength of the sealing agent used to seal the water layer is greater than ΔP, generally taken as 3 times. The required sealing strength is S = n * ΔP = 3 * ΔP.

[0033] Furthermore, the sealing radius of the main plugging agent is calculated as R = S / p; The amount of main plugging agent V3 is calculated according to the cylinder formula: V3 = π*φ * (R^2 - R1^2) * h2, where φ is the porosity of the effluent layer and h2 is the effective thickness of the effluent layer.

[0034] It should be noted that the main plugging agent injection process in this scheme is as follows: First, the coiled tubing is re-run from the wellhead, passes through the upper well section that has been sealed by the temporary plugging agent, and its end (with nozzle) is precisely lowered to the water-producing layer; Then, the main plugging agent is pumped in: the main plugging agent is pumped into the formation through the coiled tubing. During the injection process, the wellhead pressure needs to be monitored. Since the temporary plugging agent has sealed the upper layers, the pressure rises slowly and linearly, eventually reaching a certain pressure value, indicating that the main plugging agent has entered the deep formation and begun to generate significant flow resistance. After the main plugging agent is pumped in, the displacement fluid (filtered formation water from the local oilfield for compatibility) is immediately pumped in to displace all the main plugging agent inside the coiled tubing into the deep formation. Finally, the coiled tubing was pulled up to a safe position; the well was shut in, and the main plugging agent was allowed to fully solidify in the 70°C formation environment, effectively blocking the conical channel for bottom water to advance upwards.

[0035] Preferably, in step S5: after the main plugging agent has cured to the predetermined strength, the wellhead pressure monitoring determines that the main plugging agent has basically cured. The packer is then unsealed and lifted to a safe position, i.e., an unsealing ball is inserted into the tubing, pressurized to the predetermined value, the packer's locking mechanism releases, and the rubber sleeve contracts. The tubing is then slowly lifted, and the unsealed packer and its tubing string are smoothly retrieved to the surface. Inspection of the packer and rubber sleeve reveals no damage, indicating that the setting and unsealing processes were normal.

[0036] Furthermore, the design involves injecting a temporary plugging agent of a certain viscosity into the coiled tubing and tubing annulus to temporarily seal the upper oil-producing layer and the gravel-filled annulus. Simultaneously, a pre-fluid of a certain viscosity is injected into the coiled tubing to prevent the temporary plugging agent from entering the bottom water-producing layer through the gravel-filled portion. The amount of pre-fluid and the temporary plugging agent are the same, and the injection rate is also the same to prevent damage from the subsequent main plugging agent. The injection time of the main plugging agent is determined based on the gelation time of the temporary plugging agent to ensure that the plugging agent begins to enter the water-producing layer after the temporary plugging agent has gelled. The selected main plugging agent should have a low viscosity so that it can enter the water-producing layer more easily.

[0037] Meanwhile, a temporary plugging agent of a certain viscosity refers to a viscosity between 100-200 mPa·s; Furthermore, the viscosity of a pre-fluid with a certain viscosity can be calculated based on sand-filled pipe tests simulating the permeability of the water-producing and oil-producing layers. Under the same pressure and with the same amount of fluid entering, the viscosity can also be calculated using Darcy's formula.

[0038] Preferably, in step S6, the well is opened last, and the production valve is opened. In the initial stage, due to the presence of some kill fluid and construction residue in the wellbore, the fluid column pressure may be high. A small amount of gas and residual fluid may be discharged initially, but no stable oil flow is observed. If self-flow is not possible, nitrogen gas lift can be used to induce the eruption. Connect the nitrogen injection equipment and inject high-pressure nitrogen from the annulus between the tubing and casing. After the nitrogen enters the annulus, it reduces the density of the annulus fluid column, thereby reducing the bottom hole pressure. After a certain period of gas lift, oil slicks begin to appear at the wellhead. Subsequently, the oil flow gradually increases and is accompanied by gas, and then stable production is carried out.

[0039] Compared to existing water shut-off methods, which employ conventional chemical or mechanical methods, both have limitations. Conventional chemical methods are ineffective at sealing water-producing layers, while mechanical methods alone cannot effectively seal the gravel-filled portion, failing to prevent bottom water-producing layers and thus resulting in shut-off failure. Therefore, the proposed screen-tube gravel-filled well water shut-off method utilizes a packer combined with a specially selected temporary plugging agent. The temporary plugging agent seals the oil-producing section above the packer location, effectively protecting the oil layer and blocking gravel annular flow channels. Simultaneously, the injection of the main plugging agent precisely seals the deep water-producing layer, effectively protecting the oil-producing layer from damage and resolving the issue of vertical flow in the gravel-filled annulus. This combined process is suitable for screen-tube gravel-filled wells.

[0040] Finally, it should be noted that the above descriptions are merely preferred embodiments of the present invention and are not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for shutting off water in a self-flowing oil well filled with screened gravel, characterized in that: Includes the following steps: S1: Water-producing layer identification: Based on the logging data of the target well and the oil saturation data determined by numerical simulation or the production logging data of adjacent wells, the main water-producing layer is determined comprehensively. S2: Determining the setting position of the packer: Based on the cementing quality logging data, the longitudinal distance between the water-producing layer and the oil-producing layer, and the longitudinal migration distance of the temporary plugging agent in the gravel-filled annulus determined by the sand-filled pipe simulation experiment, the setting position of the packer is determined. S3: Design and construction of temporary plugging agent injection: (3a) Design of temporary plugging agent dosage: Through parallel sand-filled pipe experiments, the permeability of the oil-producing layer and the permeability of the gravel-filled annulus were simulated respectively. The depth of the temporary plugging agent entering the oil-producing layer and the longitudinal migration height in the gravel-filled annulus were measured. Based on this, the total volume of the temporary plugging agent required was calculated. (3b) Injection construction: The temporary plugging agent is injected through the annulus between the coiled tubing and the production tubing using a pump truck, so as to seal the oil-producing well section above the packer at the location and the adjacent gravel-filled annulus. S4: Design and construction of main plugging agent injection: (4a) Design of main plugging agent dosage: Based on the permeability of the water-producing layer, the formation pressure gradient of the main plugging agent is determined by sand-filled pipe experiments; the production pressure difference under the optimal daily liquid production rate is determined by reservoir numerical simulation. To ensure that the plugging strength is greater than the production pressure differential, calculate the plugging radius and dosage of the main plugging agent; (4b) Injection construction: The main plugging agent is pumped into the water-bearing section through a coiled tubing using a pump truck and then displaced from the coiled tubing; S5: Packer release and tubing lifting: After the main plugging agent has cured to the predetermined strength, release the packer and lift it to a safe position; S6: Well Opening Induced Flow: Well opening for production. If it cannot flow on its own, nitrogen gas lift will be used to induce flow.

2. The method for water shut-off in a self-flowing oil well filled with screened gravel according to claim 1, characterized in that, The temporary plugging agent used in step S3 has a viscosity of 500 mPa·s to 1000 mPa·s at reservoir temperature.

3. A method for shutting off water in a self-flowing oil well filled with screened gravel according to claim 2, characterized in that, The viscosity of the primary plugging agent used in step S4 is 0 mPa·s to 200 mPa·s at reservoir temperature.

4. The method for shutting off water in a self-flowing oil well filled with screened gravel according to claim 3, characterized in that, In step S3, after the temporary plugging agent is injected, a temporary plugging agent plug with a certain height is formed in the gravel-filled annulus above the packer. This plug can effectively prevent the subsequent main plugging agent from migrating indefinitely in the longitudinal direction, thereby achieving efficient separation of the wellbore and the reservoir.

5. The method for water shut-off in a self-flowing oil well filled with screened gravel according to claim 1, characterized in that, The step S2 of determining the packer setting position specifically includes: S21. Select a suitable well section as a candidate setting location; S22. Conduct a sand-filled pipe simulation experiment: Establish a parallel sand-filled pipe model, with one pipe simulating the permeability K2 of the oil-producing layer and the other pipe simulating the permeability K1 of the gravel-filled annulus; inject a temporary plugging agent and record the injection pressure P1 when it enters a certain depth of the simulated oil-producing layer, as well as the longitudinal migration height h1 of the temporary plugging agent in the simulated gravel-filled pipe under the pressure P1, which is the deepest position of the packer setting position from the top of the water-producing layer; S23. Calculate the safety distance: Use the experimentally measured h1 as the expected longitudinal migration distance of the temporary plugging agent in the actual gravel-filled annulus downhole; S24. Determine the setting depth: The setting depth of the packer should ensure that the vertical distance between its lower end face and the top boundary of the outlet layer is not less than h1, and should preferably be selected within the candidate setting position range determined in S21.

6. The method for shutting off water in a self-flowing oil well filled with screened gravel according to claim 5, characterized in that, The specific design of the temporary plugging agent dosage in step S3 is as follows: Based on the depth L0 of the temporary plugging agent entering the simulated oil-producing layer determined by the sand-filled pipe experiment, the volume of the temporary plugging agent entering the actual oil-producing layer is calculated using the cylinder formula: V1 = π * (R1^2 - R2^2) * L0, where R1 is the wellbore radius and R2 is the outer radius of the screen pipe. Based on the longitudinal transport height h of the temporary plugging agent in the simulated gravel-filled annulus determined by the sand-filled pipe experiment, calculate the volume of the temporary plugging agent occupying the gravel-filled annulus: V2 = π * [(R1^2 - R3^2) - (R2^2 - R3^2)] * h1, where R3 is the inner radius of the sieve tube. The total amount of temporary plugging agent used, Vtotal, is equal to V1 plus V2.

7. The method for water shut-off in a self-flowing oil well filled with screened gravel according to claim 1, characterized in that, The specific design of the main plugging agent dosage in step S4 is as follows: The pressure gradient p of the main plugging agent under simulated effluent permeability conditions was determined through sand-filled pipe experiments. By using reservoir numerical simulation, the bottom hole flowing pressure of the oil well under the optimal daily fluid production rate Q after water control is determined, and then the production pressure difference ΔP between the well and the formation pressure is calculated. The sealing strength of the main plugging agent is designed as S = n * ΔP, where n is the safety factor, which takes a value greater than 1; Calculate the sealing radius of the main plugging agent: R = S / p; The amount of main plugging agent V3 is calculated according to the cylinder formula: V3 = π*φ * (R^2 - R1^2) * h2, where φ is the porosity of the effluent layer and h2 is the effective thickness of the effluent layer.

8. The method for shutting off water in a self-flowing oil well filled with gravel and screen pipes according to claim 1, characterized in that, In step S1, the identification of the water-producing layer can be performed by directly determining the main water-producing layer based on the water production of each section when production logging data is available. When production logging data is unavailable, the water-producing layer information of adjacent wells and logging data of this well can be combined with numerical simulation technology to invert the data or by judging the distribution law of permeability and oil saturation.

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