Methods, treatment measures, and equipment for identifying pressurized leaks in the annulus of CO2 injection wells.

Abstract

The application belongs to the technical field of oil and gas field development, and discloses a CO2 flooding gas injection well annular pressure leakage point discrimination method, treatment measures and a device. The method comprises the following steps: during the injection stop, sampling is carried out by using a field oil casing annular sampling valve, the return of annular protection fluid is observed, and the leakage point position is judged in combination with the oil casing pressure change dynamic in the previous gas injection process; if no annular protection fluid is returned during sampling, and the returned medium is all gas, then pressure relief testing is carried out through the external discharge pipeline, during the pressure relief process, the external discharge valve is kept at a constant opening, and the tubing pressure, casing pressure, output gas composition and output gas temperature change are recorded at the same time; according to the obtained pressure relief condition, in combination with the output gas composition and temperature change, the leakage point position is judged. The application comprehensively analyzes and judges the leakage point by the oil casing annular sampling, the oil casing pressure, the output gas composition and the temperature change during the casing pressure relief process, and provides an important basis for the annular pressure leakage reason judgment and risk control in the CCUS development process.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a method, treatment measures and device for identifying pressurized leakage points in the annulus of CO2-driven gas injection wells, which is particularly applicable to pressurized gas injection wells in the annulus of CCUS (carbon capture, utilization and storage). Background Technology

[0002] CCUS-EOR (Carbon Dioxide Capture, Utilization, Storage, and Enhanced Oil Recovery) technology significantly improves the recovery rate of low-permeability, ultra-low-permeability, and unconventional oil reservoirs while also reducing and fixing carbon, offering substantial economic and social benefits. Maintaining wellbore integrity is crucial for the successful implementation of CCUS projects during gas injection. Failure to maintain wellbore integrity can lead to overpressure or damage to downhole tubing, casing, and packers. Furthermore, high CO2 partial pressure conditions exacerbate corrosion of the wellhead and downhole tubing, severely impacting the lifespan of gas-sealing components and the tubing string, thus posing risks to the safe operation of the injection well.

[0003] like Figure 1 As shown, the key integrity components in the CO2-driven gas injection well tubing string structure include: 1. Tree trunk; 2. Casing head; 3. Tubing hanger; 4. Tubing and threads; 5. Variable thread sealing sub; 6. Packer; 7. Cement sheath; and 8. Among these, leak locations in pressurized annulus wells with CO2-driven gas injection mainly include leaks in the tubing hanger, tubing corrosion perforation, tubing threads, packer, and casing. Leaks in any of these locations will cause an increase in pressure in the annulus (also known as the A-annulus), leading to wellbore integrity failure. Taking existing CCUS projects as an example, the proportion of pressurized annulus in injection wells is as high as 46%. Existing noise and fiber optic leak detection methods have high accuracy, but require stopping gas injection and deploying specialized testing tools, resulting in high testing costs and a long assessment time, generally exceeding 24 hours or even requiring a week to obtain test results. Therefore, there is an urgent need to develop a rapid and efficient method for identifying pressurized annulus leak points in CO2-driven gas injection wells, providing a basis for annulus pressurization cause analysis and the formulation of control measures. Summary of the Invention

[0004] This invention aims to solve the problem of identifying and managing pressurized leaks in the annulus of CO2 injection wells during CCUS-EOR (Carbon Dioxide Capture, Utilization, Storage and Enhanced Oil Recovery). It provides a method, treatment measures and device for identifying pressurized leaks in the annulus of CO2-driven injection wells, and comprehensively analyzes the changes in annulus pressure, produced gas composition and temperature during casing depressurization, based on annular sampling, casing pressure, and temperature changes. This provides important evidence for judging the causes of annular pressure and managing risks during CCUS development.

[0005] To achieve the above technical objectives, the present invention adopts the following technical solution: A method for identifying pressurized leak points in the annulus of CO2-driven gas injection wells, the method comprising the following steps: Step S101: During the injection stoppage, take samples using the on-site oil jacket annulus sampling valve, observe the return of annulus protective fluid, and determine the location of the leak point by combining the dynamic changes in oil jacket pressure during the previous gas injection process. Step S102: If no annular protective fluid is returned from the sample and the returned medium is all gas, then connect the external discharge pipeline for a pressure relief test. During the pressure relief process, the external discharge valve maintains a constant opening, and the changes in oil pipe pressure, casing pressure, gas composition and gas temperature are recorded. Step S103: Based on the pressure relief situation obtained in step S102, and combined with the changes in the composition and temperature of the produced gas, determine the location of the leak point.

[0006] Furthermore, in step S101, if the annular protection fluid is immediately returned when the on-site oil jacket annular sampling valve takes a sample, then packer leakage is ruled out. In addition, the location of the leak point is determined by combining the dynamic changes in oil jacket pressure during the previous gas injection process.

[0007] Furthermore, the method of determining the location of the leak by combining the dynamic changes in oil and casing pressure during the previous gas injection process includes: if the casing pressure rise rate is >1MPa / d and the oil and casing pressure difference is <0.5MPa, the leak location is determined to be a pipe malfunction; if the casing pressure rise rate is <0.1MPa / d, the leak location is determined to be a micro-leakage in the oil pipe and / or casing thread.

[0008] Furthermore, in step S102, the changes in tubing pressure, casing pressure, produced gas composition, and produced gas temperature are recorded simultaneously, specifically as follows: During the depressurization process, at least two oil pipe pressure values, two casing pressure values, and two gas temperature values ​​should be recorded per minute, and at least three gas composition values ​​should be recorded throughout the entire depressurization process.

[0009] Further, step S103 specifically includes: If the pressure drop is less than 2 MPa after 30 minutes of depressurization, and the pressure returns to the pre-depressurization level within 2 hours after depressurization is stopped, and the hydrocarbon content in the produced gas exceeds 1%, and the hydrocarbon content and the temperature of the produced gas show an upward trend, then the packer seal is judged to be faulty. If the packing pressure is completely released within 30 minutes, it is determined that the packer has suffered a partial sealing failure.

[0010] Meanwhile, the present invention also provides a measure for handling pressurized leaks in the annulus of CO2-driven gas injection wells, wherein the leak is identified using any of the above-mentioned leak identification methods, and the handling measure includes: If the leak is determined to be in the oil pipe hanger, the following measures should be taken: pressure test and seal the oil pipe hanger, and then inject sealant to reseal the oil pipe hanger. If the leak is determined to be a minor leak in the tubing and / or casing threads, the following measures should be taken: continue to strengthen monitoring and periodically depressurize after the annular pressure limit is reached. If the leak is determined to be due to packer seal failure, the appropriate action is to complete the well again and replenish the annulus protection fluid. If the leak is located at a point where the packer's seal has failed, the appropriate action is to seal the leak using resin gel.

[0011] In addition, the present invention also provides a device for identifying pressurized leak points in the annulus of a CO2-driven gas injection well, for implementing any of the above-mentioned leak point identification methods. The device includes an external discharge pipeline, the inlet end of which is connected to the gas production tree of the injection well, and the outlet end of which is connected to a tank truck. A gas component detector and an electronic temperature monitoring device are installed on the external discharge pipeline.

[0012] Compared with the prior art, the beneficial effects of the present invention are: (1) The method for identifying leak points in the annulus of CO2-driven gas injection wells provided by this invention analyzes and judges the leak points by comprehensively considering various factors such as annulus sampling, annulus pressure, gas composition and temperature changes during casing depressurization. Without the need to run downhole testing tools, the time required for leak point judgment is reduced by more than 80% and the accuracy rate reaches more than 95%. This enables rapid and accurate location of leaks and provides an important basis and scientific processing procedure for judging the cause of annulus pressure and risk management during CCUS development. (2) The CO2-driven gas injection well annulus pressurized leak point identification device provided by the present invention has a gas component detector and an electronic temperature detection device installed on the external discharge pipeline. It can record the gas return gas component and temperature changes in real time, and effectively ensure the rapid and accurate identification of the leak point location by taking into account the pressure factors and the return of the gas injection well annulus protective fluid. Attached Figure Description

[0013] Figure 1 A schematic diagram of the key nodes and components for the integrity of the tubing string in a CO2-driven gas injection well. Figure 2 This is a flowchart illustrating the methods for determining and handling annular pressurized leak points according to an embodiment of the present invention. Figure 3 This is a pressure relief-recovery curve of the annulus in well A according to an embodiment of the present invention; The markings in the diagram are as follows: 1-Gaseous tree; 2-Casing head; 3-Tubing hanger; 4-Tubing and thread; 5-Variable thread sealing short section; 6-Packer; 7-Cement ring; 8-Casing. Detailed Implementation

[0014] The technical solutions of 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.

[0015] Example 1 This invention provides a method for identifying pressurized leak points in the annulus of CO2-driven gas injection wells, combined with... Figure 2 As shown, the method specifically includes the following steps: Step S101: During the injection stoppage, take samples using the on-site oil jacket annulus sampling valve, observe the return of annulus protective fluid, and determine the location of the leak point by combining the dynamic changes in oil jacket pressure during the previous gas injection process. Specifically, if the annular sampling valve immediately returns annular protective fluid during sampling, packer leakage is ruled out. Further analysis is conducted based on the dynamic changes in oil and casing pressure during the previous gas injection process. If the casing pressure rise rate is >1MPa / d and the oil and casing pressure difference is <0.5MPa, the leak location is determined to be tubing snagging. If the casing pressure rise rate is <0.1MPa / d, the leak location is determined to be micro-leakage in the tubing and / or casing threads.

[0016] Step S102: If no annular protective fluid is returned from the sample and the returned medium is entirely gas, then connect the external discharge pipeline for a pressure relief test. During the pressure relief process, the external discharge valve maintains a constant opening, and the changes in oil pipe pressure, casing pressure, gas composition, and gas temperature are recorded simultaneously. Record the oil pipe pressure value, casing pressure value, and gas temperature value twice per minute, and record the gas composition value three times throughout the entire pressure relief process.

[0017] Step S103: Based on the pressure relief information obtained in step S102, and combined with the changes in the composition and temperature of the produced gas, determine the location of the leak point; specifically including: If the pressure drop is less than 2 MPa after 30 minutes of depressurization, and the pressure returns to the pre-depressurization level within 2 hours after depressurization is stopped, and the hydrocarbon content in the produced gas exceeds 1%, and the hydrocarbon content and the temperature of the produced gas show an upward trend, then the packer seal is judged to be faulty. If the packing pressure is completely released within 30 minutes, it is determined that the packer has suffered a partial sealing failure.

[0018] Example 2 This invention provides a method for handling pressurized leaks in the annulus of CO2-driven gas injection wells. The leak point identification method described in Example 1 is used for leak point identification. The handling method specifically includes: If the leak is determined to be at the oil pipe hanger, then pressure test and seal the oil pipe hanger and inject sealant to reseal it. If the leak is determined to be a micro-seepage in the tubing and / or casing threads, then continuous monitoring should be strengthened, and periodic depressurization should be carried out after the annular pressure limit is reached. Since the micro-seepage leakage is small, it has little impact on the integrity of the gas injection string. Periodic depressurization in the case of micro-seepage can alleviate the micro-seepage leakage, and the cost is much lower than that of re-completion. If the leak is determined to be due to packer seal failure, then complete the well again and replenish the annulus protection fluid; If the leak is determined to be a localized failure of the packer's seal, then resin gel should be used to seal the leak in the packer.

[0019] Example 3 This invention provides a device for identifying pressurized leak points in the annulus of a CO2-driven gas injection well, used to implement the leak point identification method described in Embodiment 1 above. The device includes an external discharge pipeline, the inlet end of which is connected to the gas production tree of the injection well, and the outlet end of which is connected to a receiving truck. A gas component detector and an electronic temperature monitoring device are installed on the external discharge pipeline.

[0020] Example 4 This invention provides a method for identifying pressurized annulus leaks in CO2-driven gas injection wells. The method was applied to well A in a CO2-driven block in Xinjiang Oilfield. Well A is a CO2 injection well with an injection rate of 20 t / d. After 17 days of continuous injection, the oil pressure was 14.3 MPa, the annulus pressure was 11.6 MPa (maximum permissible annulus pressure 21 MPa), and the oil-casing pressure difference was 2.7 MPa. After 15 days of injection cessation, the oil pressure was 5.38 MPa, and the casing pressure was 5.01 MPa. The method described in Embodiment 1 of this invention was used to identify annulus leaks. The specific identification process is as follows: (1) First, open the oil jacket annulus sampling valve to take a sample. No water-based annulus protection fluid is returned, and the returned medium is all gas. (2) Then, connect the external discharge pipeline, install a gas component detector and an electronic temperature monitoring device, connect the external discharge pipeline outlet to the tanker truck, open the external discharge valve, keep it at 1 / 3 opening, and start depressurization; during the depressurization process, record 2 oil-casing pressure values ​​every minute, and record the changes in gas composition at the same time. Continue depressurization for 35 minutes. The oil pressure drops to 5.0 MPa and the casing pressure drops to 4.56 MPa. Complete depressurization cannot be achieved. The oil and casing pressure curves are as follows: Figure 3 As shown in the curve on the left side, the changes in the composition and temperature of the produced gas during the depressurization process are shown in Table 1 below; based on the composition and temperature of the produced gas, it is determined that the gas injection tubing is communicating with the formation, and the packer seal has failed. Table 1. Changes in gas composition and temperature during the depressurization process.

[0021] (3) Further, shut off the pipeline outside the pipeline and record the oil and casing pressure recovery status. Record one data point every 3 minutes. The pressure recovery curve is as follows: Figure 3 The curve on the right side of the middle section is shown.

[0022] (4) Based on comprehensive judgment, the pressurized leak in the annulus of well A was determined to be due to packer seal failure. The entire process of determining the pressurized leak point in the annulus took less than 2 hours, thus achieving the determination of the leak location. Later on-site fiber optic leak detection in the well revealed that the leak channel at the packer location was large, verifying the effectiveness of the method.

[0023] The above description is merely an embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, and improvements made within the scope of the present invention should be included within the protection scope of the present invention.

Claims

1. A CO2 flooding gas injection well annulus pressure carrying leakage point discrimination method, characterized in that, The method includes the following steps: Step S101: During the injection stoppage, use the on-site oil jacket annulus sampling valve to take samples, observe the return of annulus protective fluid, and combine the dynamic changes in oil jacket pressure during the previous gas injection process to determine the location of the leak point. If the annular fluid is immediately returned when the on-site oil jacket annular sampling valve is used for sampling, packer leakage is ruled out. Further analysis of the dynamic changes in oil jacket pressure during the previous gas injection process can help determine the location of the leak. If the casing pressure rise rate is >1MPa / d and the oil-casing pressure difference is <0.5MPa, the leak location is determined to be tubing snagging; if the casing pressure rise rate is <0.1MPa / d, the leak location is determined to be micro-leakage in the tubing and / or casing threads. Step S102: If no annular protective fluid is returned from the sample and the returned medium is all gas, then connect the external discharge pipeline for a pressure relief test. During the pressure relief process, the external discharge valve maintains a constant opening, and the changes in oil pipe pressure, casing pressure, gas composition and gas temperature are recorded. Step S103: Based on the pressure relief situation obtained in step S102, and combined with the changes in the composition and temperature of the produced gas, determine the location of the leak point; If the pressure drop is less than 2 MPa after 30 minutes of depressurization, and the pressure returns to the pre-depressurization level within 2 hours after depressurization is stopped, and the hydrocarbon content in the produced gas exceeds 1%, and the hydrocarbon content and the temperature of the produced gas show an upward trend, then the packer seal is judged to be faulty. If the packing pressure is completely released within 30 minutes, it is determined that the packer has suffered a partial sealing failure.

2. The leak point identification method according to claim 1, characterized in that, In step S102, the changes in tubing pressure, casing pressure, produced gas composition, and produced gas temperature are recorded simultaneously, specifically as follows: During the depressurization process, at least two oil pipe pressure values, two casing pressure values, and two gas temperature values ​​should be recorded per minute, and at least three gas composition values ​​should be recorded throughout the entire depressurization process.

3. A method for handling pressurized leaks in the annulus of a CO2-driven gas injection well, characterized in that the leak point is identified using the leak point identification method as described in claim 1 or 2, and that... The measures to be taken include: If the leak is determined to be in the oil pipe hanger, the following measures should be taken: pressure test and seal the oil pipe hanger, and then inject sealant to reseal the oil pipe hanger. If the leak is determined to be a micro-leakage in the tubing and / or casing threads, the following measures should be taken: continue to strengthen monitoring and periodically depressurize after the annular pressure limit is reached. If the leak is determined to be due to packer seal failure, the appropriate action is to complete the well again and replenish the annulus protection fluid. If the leak is located at a point where the packer's seal has failed, the appropriate action is to seal the leak using resin gel.

4. A device for identifying pressurized leak points in the annulus of a CO2-driven gas injection well, used to implement the leak point identification method described in claim 1 or 2, characterized in that, The device includes an external discharge pipeline, the inlet end of which is connected to the gas production tree of the injection well, and the outlet end of which is connected to a tank truck. A gas component detector and an electronic temperature monitoring device are installed on the external discharge pipeline.

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