Gas injection well downhole oil pipe leakage monitoring system and method

Abstract

The invention discloses a gas injection well underground oil pipe leakage monitoring system and method, and the method comprises the steps: placing an optical fiber in an oil pipe, placing the optical fiber in a designated position in the oil pipe, injecting gas into the oil pipe until a pressure difference is generated, stopping gas injection, closing a valve of the oil pipe, and standing for a period of time; amplitude basic noise and phase basic noise in a stable state at the moment are collected; continuing to wait for a period of time to increase the pressure in the well to a specified value, opening a casing valve, collecting corresponding sound wave data, closing the casing valve if the suspected leakage position cannot be found by amplitude data, repeating the previous operation, collecting sound wave data of a plurality of pressures, and determining the leakage position. And performing spectral analysis on the data collected at the highest pressure until the amplitude can distinguish the suspected leakage position or the pressure cannot be continuously increased to find the suspected leakage position, and judging the leakage position and the leakage type according to the amplitude signal intensity and the frequency range of the phase. Therefore, according to the method, the leakage position and the leakage type are judged by monitoring and analyzing the collected data.

Description

Technical Field

[0001] This invention belongs to the field of gas-driven tertiary oil recovery and relates to a system and method for monitoring leakage in the downhole tubing of gas injection wells. Background Technology

[0002] Currently, most oilfields are in the mid-to-late stages of development, and conventional primary and secondary oil recovery technologies are no longer effective in improving oil recovery rates. Gas injection is an important method to improve the recovery rate of low-permeability, tight oil reservoirs. Gases have the advantages of high stability and easy flow, giving them a significant advantage in the development of low-permeability reservoirs. Furthermore, gas injection is less affected by formation water salinity. This technology involves various types of gas injection, mainly including hydrocarbon gases, carbon dioxide, nitrogen, flue gas, and air.

[0003] During the injection process, the high-pressure fluid in gas injection wells is highly corrosive, making the tubing susceptible to corrosion and damage during long-term production. Leaks at tubing connection points can also compromise the integrity of the wellbore. Existing methods mostly only allow for localized detection and cannot cover the entire wellbore. Therefore, a convenient and efficient wellbore integrity monitoring solution is urgently needed to achieve real-time monitoring of the entire wellbore. Through research, CN209876527U discloses an automatic tubing leak detection system, including an oil storage tank, an oil pipeline, and a monitoring unit. The oil pipeline is connected to the outlet of the oil storage tank. The oil pipeline is sequentially equipped with an oil outlet control valve, an oil pump, an oil flow meter, and a monitoring unit. The monitoring unit includes a flow monitoring unit and a pressure monitoring unit. The flow monitoring unit includes a flow control display and several liquid flow meters evenly distributed along the oil pipeline, all connected to the flow control display. The pressure monitoring unit includes a pressure control display and several pressure gauges evenly distributed along the oil pipeline, all connected to the pressure control display. The end of the oil pipeline is connected to the user end. Simultaneous monitoring of pressure and flow rate can reduce the error rate of oil pipeline leak detection, improve monitoring accuracy, and accurately locate the leak point for timely repair, ensuring safe transportation. CN109339769A discloses an integrated downhole tubing leak surface detection system, which includes an acoustic detection subsystem, a tracer injection detection subsystem, a liquid level detection subsystem, and a monitoring and control system. This invention can complete the monitoring and diagnosis of downhole tubing leaks on the surface without interfering with the daily production of oil and gas wells, achieving low-cost and high-efficiency detection. CN207034654U discloses a tubing leak detection system, consisting of a monitoring device, an oil pipeline, and an oil storage tank, which can detect pipeline leaks in real time. This utility model patent mainly targets the detection of leaks in long-distance pipelines. CN116296125A discloses an oil casing leak detection system, method, and device, including an ultrasonic detection device and a host computer. The ultrasonic detection device includes a piezoelectric ultrasonic sensor and an electromagnetic ultrasonic sensor, which are evenly and alternately arranged and distributed circumferentially along the ultrasonic detection device. The host computer receives and analyzes the ultrasonic signals transmitted by the ultrasonic detection device to determine the source of the leak. This invention utilizes the principles and characteristics of two ultrasonic sensors to capture ultrasonic signals from leaks in the tubing and production casing, respectively, enabling ultrasonic signal detection of leaks in both tubing and production casing. This provides a feasible method for locating and detecting leaks in the tubing and production casing of in-service wells. However, existing technologies cannot provide real-time and efficient monitoring of tubing integrity. Summary of the Invention

[0004] The purpose of this invention is to solve the problem that existing technologies cannot monitor the integrity of tubing in real time and efficiently, and to provide a system and method for monitoring leaks in downhole tubing in gas injection wells.

[0005] To achieve the above objectives, the present invention employs the following technical solution:

[0006] The present invention proposes a downhole tubing leakage monitoring system for gas injection wells, comprising tubing installed inside the production casing and packers and perforations installed on the outer wall of the production casing; an optical fiber is provided in the tubing, and a DAS for collecting amplitude and phase fundamental noise is connected to one end of the optical fiber; and a tubing valve is also provided on the tubing.

[0007] This invention proposes a method for monitoring leaks in the downhole tubing of gas injection wells, comprising the following steps:

[0008] Install the packer and perforation outside the production casing, install the optical fiber inside the tubing, inject gas into the tubing until a pressure differential is generated, then stop injecting gas, close the tubing valve and let it stand, and use DAS to obtain amplitude noise data and phase noise data of the tubing under stable conditions.

[0009] When the pressure inside the well reaches the set pressure value, open the tubing valve and use DAS to collect the corresponding acoustic data.

[0010] If the acoustic data indicates a suspected leak location, close the oil pipe valve and repeat the above steps to collect acoustic data at several pressures until the acoustic data amplitude distinguishes the suspected leak location or the pressure can no longer be increased.

[0011] The acoustic data did not reveal any suspected leak location. Spectral analysis was performed on the acoustic and noise data collected at the highest pressure to determine the leak location and type.

[0012] Preferably, the steps for obtaining the amplitude and phase fundamental noise are as follows:

[0013] Step 1: Average the amplitude data of the entire first frame to obtain a1. Calculate the FBE of the phase data of the entire first frame on [0, f1], (f1, f2), and [f2, f / 2] respectively, and average them to obtain (b). 11 ,b 21 ,b 31 ); where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage;

[0014] Step 2: Perform the amplitude operation from Step 1 on each frame of amplitude data collected to obtain n amplitude mean data a1, a2…a n Where n is the number of amplitude frames acquired by DAS within 10 minutes; perform the phase operation in step 1 on each frame of phase data acquired within 10 minutes to obtain n sets of phase FBE mean data (b 11 ,b 21 ,b 31 ), (b 12 ,b22 ,b 32 ...(b 1n ,b 2n ,b 3n ), where n is the number of phase frames acquired by DAS within 10 minutes;

[0015] Step 3: For a1, a2…a n Sum and average to obtain the amplitude basis noise 'a', and for 'b'... 11 b 12 …b 1n By summing and averaging, we obtain the phase FBE base noise b1 in the interval [0, f1], and similarly, the phase FBE base noise b2 in the interval (f1, f2) and the phase FBE base noise b3 in the interval [f2, f / 2].

[0016] Preferably, the length of the dropped optical fiber is greater than the depth of the location to be monitored.

[0017] Preferably, after the wellhead is lowered, the wellhead position is determined by tapping the wellhead and the DAS amplitude change is used to calibrate the length of the fiber optic cable at the wellhead to 0.

[0018] Preferably, the method for obtaining the leak location and leak type is as follows:

[0019] The collected amplitude data is compared with a threshold. If the amplitude continuously exceeds the threshold, the location is considered a suspected leak location; if the amplitude does not continuously exceed the threshold, there is no leak at that location.

[0020] The frequency is divided into three intervals: [0, f1], (f1, f2), [f2, f / 2], where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage. Calculate the FBE value of the signal in each frequency band within 10 minutes.

[0021] If all FBE values ​​in the (f1, f2) frequency band are greater than the corresponding FBE threshold within 10 minutes, and the FBE values ​​in the other two frequency bands are less than the corresponding FBE threshold, then the location is determined to be a leakage location; otherwise, it is noise.

[0022] Preferably, the threshold is adjusted based on the on-site basic amplitude noise data and is set to 5 times the amplitude noise data.

[0023] Preferably, the FBE threshold is related to the phase noise data, and the FBE threshold in each frequency band is 5 times the phase noise data in each frequency band.

[0024] Preferably, the FBE is calculated as follows:

[0025]

[0026] Where m is the number of points in the FFT frequency range of the signal, and P is the FFT value corresponding to each frequency.

[0027] Preferably, the pressure value is determined by the measured gas well pressure level and the leakage of the tubing.

[0028] Compared with the prior art, the present invention has the following beneficial effects:

[0029] This invention proposes a method for monitoring leaks in downhole tubing of gas injection wells. The method involves lowering an optical fiber into the tubing at a designated location. Gas is injected into the tubing until a pressure differential is achieved, then injection is stopped, and the tubing valve is closed. After a period of settling, the amplitude and phase fundamental noise of the stable state are collected using a DAS (Digital Animation Sensor). The process continues until the well pressure reaches a designated value. The casing valve is then opened, and corresponding acoustic data is collected using the DAS. If the DAS amplitude data cannot locate the suspected leak, the casing valve is closed, and the process is repeated, collecting acoustic data at various pressures until the DAS amplitude can distinguish the suspected leak or the pressure can no longer be increased to find the leak. The DAS data collected at the highest pressure is then subjected to spectral analysis. Based on the frequency range of the DAS amplitude signal strength and DAS phase, the leak location and type are determined. This method utilizes a complete optical fiber sensing process and effective data processing to monitor and analyze the collected DAS data, determining the leak location and type. It offers the advantages of automatic and real-time monitoring.

[0030] Furthermore, after the wellhead is lowered, the wellhead position is determined by tapping the wellhead and changing the DAS amplitude. The fiber length at the wellhead is then calibrated to 0, so that the fiber length corresponds to the depth of the well.

[0031] Furthermore, the frequency is divided into three intervals because the leakage signal is mainly concentrated in the intermediate frequency. Therefore, the FBE energy value in the intermediate frequency band is relatively large, that is, the energy is relatively large in the (f1, f2) frequency band, while the energy in other bands is relatively small. Attached Figure Description

[0032] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0033] Figure 1 This is a structural diagram of the gas injection well downhole tubing leakage monitoring system of the present invention.

[0034] Figure 2 This is a flowchart of the gas injection well downhole tubing leakage monitoring method of the present invention.

[0035] Figure 3 This is a detailed flowchart of the monitoring method of the present invention.

[0036] Figure 4 This is a diagram showing the DAS amplitude at various locations in the wellbore at 12 MPa, according to the present invention.

[0037] Figure 5 This is a schematic diagram of the data processing flow of the present invention.

[0038] Among them: 1-production casing, 2-oil tubing, 3-packer, 4-perforation, 5-optical fiber, 6-DAS. Detailed Implementation

[0039] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, 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. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0040] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0041] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0042] In the description of the embodiments of the present invention, it should be noted that if terms such as "upper," "lower," "horizontal," or "inner" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship commonly used when the product of the invention is in use, they are only for the convenience of describing the present invention and simplifying the description, and do not 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 present invention. Furthermore, terms such as "first" and "second" are only used to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0043] Furthermore, the use of the term "horizontal" does not imply that the component must be absolutely horizontal, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0044] In the description of the embodiments of the present invention, it should also be noted that, unless otherwise explicitly specified and limited, the terms "set," "install," "connect," and "link" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in the present invention according to the specific circumstances.

[0045] The present invention will now be described in further detail with reference to the accompanying drawings:

[0046] This invention proposes a downhole tubing leakage monitoring system for gas injection wells, such as... Figure 1 As shown in the figure, the oil pipe has two damaged sections. These include the oil pipe 2 installed inside the production casing 1, and the packer 3 and perforation 4 installed on the outer wall of the production casing 1. An optical fiber 5 is installed in the oil pipe 2, and a DAS 6 for collecting amplitude and phase fundamental noise is connected to one end of the optical fiber 5. There is also an oil pipe valve on the oil pipe 2.

[0047] This invention proposes a method for monitoring leaks in the downhole tubing of gas injection wells, such as... Figure 2 As shown, it includes the following steps:

[0048] S1. Install the packer and perforation outside the production casing, install the optical fiber inside the oil pipe, inject gas into the oil pipe until a pressure difference is generated, then stop injecting gas, close the oil pipe valve and let it stand, and use DAS to obtain the amplitude noise data and phase noise data of the oil pipe under stable conditions.

[0049] The length of the lowered optical fiber is greater than the depth of the location to be monitored. After lowering, the wellhead is tapped to determine its position by observing the change in DAS amplitude, and the length of the optical fiber at the wellhead is calibrated to 0.

[0050] The set pressure value is determined by the measured gas well pressure level and the amount of leakage in the tubing.

[0051] The steps to obtain the amplitude and phase fundamental noise are as follows:

[0052] Step 1: Average the amplitude data of the entire first frame to obtain a1. Calculate the FBE of the phase data of the entire first frame on [0, f1], (f1, f2), and [f2, f / 2] respectively, and average them to obtain (b). 11 ,b 21 ,b 31 ); where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage;

[0053] Step 2: Perform the amplitude operation from Step 1 on each frame of amplitude data collected within 10 minutes to obtain n amplitude mean data points a1, a2…a n Where n is the number of amplitude frames acquired by DAS within 10 minutes; perform the phase operation in step 1 on each frame of phase data acquired within 10 minutes to obtain n sets of phase FBE mean data (b 11 ,b 21 ,b 31 ), (b 12 ,b 22 ,b 32 ...(b 1n ,b 2n ,b 3n ), where n is the number of phase frames acquired by DAS within 10 minutes;

[0054] Step 3: For a1, a2…a n Sum and average to obtain the amplitude basis noise 'a', and for 'b'... 11 b 12 …b 1n By summing and averaging, we obtain the phase FBE base noise b1 in the interval [0, f1], and similarly, the phase FBE base noise b2 in the interval (f1, f2) and the phase FBE base noise b3 in the interval [f2, f / 2].

[0055] S2. When the well pressure rises to the set pressure value, open the tubing valve and use DAS to collect the corresponding acoustic data.

[0056] S3. If the acoustic data indicates a suspected leak location, close the oil pipe valve and repeat the above steps to collect acoustic data at several pressures until the acoustic data amplitude distinguishes the suspected leak location or the pressure can no longer be increased.

[0057] S4. If no suspected leak location is found in the acoustic data, perform spectral analysis on the acoustic and noise data collected at the highest pressure to determine the leak location and type.

[0058] The methods for obtaining the leak location and leak type are as follows:

[0059] The collected amplitude data is compared with a threshold. If the amplitude continuously exceeds the threshold, the location is considered a suspected leak location; if the amplitude does not continuously exceed the threshold, there is no leak at that location.

[0060] The frequency is divided into three intervals: [0, f1], (f1, f2), [f2, f / 2], where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage. Calculate the FBE value of the signal in each frequency band within 10 minutes.

[0061] If all FBE values ​​in the (f1, f2) frequency band are greater than the corresponding FBE threshold within 10 minutes, and the FBE values ​​in the other two frequency bands are less than the corresponding FBE threshold, then the location is determined to be a leakage location; otherwise, it is noise.

[0062] The threshold is adjusted based on the on-site basic amplitude noise data and is set to 5 times the amplitude noise data.

[0063] The FBE threshold is related to the phase noise data, and the FBE threshold for each frequency band is five times the phase noise data for that band. The calculation method for FBE is as follows:

[0064]

[0065] Where m is the number of points in the FFT frequency range of the signal, and P is the FFT value corresponding to each frequency.

[0066] The monitoring method process is as follows: Figure 3 As shown, the detailed steps are as follows:

[0067] Step 1: Using the method of lowering the optical fiber inside the tubing, the optical fiber is lowered to the designated position inside the tubing. Gas is injected into the tubing until a pressure differential is generated, then gas injection is stopped, and the tubing valve is closed. The length of the lowered optical fiber must be at least 20 meters greater than the depth of the location to be monitored. After lowering, the wellhead is tapped to determine the wellhead position by observing the change in DAS amplitude. The length of the optical fiber at the wellhead is calibrated to 0, so that the fiber length corresponds to the depth of the well. In this embodiment of the invention, the length of the optical fiber lowered into the wellbore is 3200 meters.

[0068] Step 2: After a period of stillness, use DAS to collect the amplitude and phase fundamental noise under this stable state. The DAS data is divided into amplitude and phase data of the acoustic wave. The spatial sampling rate can be set, typically 0.4m or 2m. This embodiment uses a 0.4m resolution, meaning one sampling point represents 0.4m of fiber. Within a certain range, the amplitude signal acquired by DAS is basically positively correlated with the magnitude of the acoustic event. The environmental noise is the DAS signal collected when the fiber is undisturbed; at this time, the DAS amplitude signal has no obvious disturbance and remains at a low level. The specific calculation steps for amplitude and phase fundamental noise are as follows:

[0069] Step 2-1: Average the amplitude data of the entire first frame to obtain a1. Calculate the FBE of the phase data of the entire first frame on [0, f1], (f1, f2), and [f2, f / 2] respectively, and average them to obtain (b). 11 ,b 21 ,b 31 );

[0070] Step 2-2: Perform the amplitude operation in Step 2-1 on each frame of amplitude data collected within 10 minutes to obtain n amplitude mean data a1, a2…a n Where n is the number of amplitude frames acquired by DAS within 10 minutes. Perform the phase operation in step 2-1 on each frame of phase data acquired within 10 minutes to obtain n sets of phase FBE mean data (b 11 ,b 21 ,b 31 ), (b 12 ,b 22 ,b 32 ...(b 1n ,b 2n ,b 3n ), where n is the number of phase frames acquired by DAS within 10 minutes.

[0071] Steps 2-3: For a1, a2…a n Sum and average to obtain the amplitude-based fundamental noise 'a'. For 'b'... 11 b 12 …b 1n By summing and averaging, we obtain the phase FBE base noise b1 in the interval [0, f1], and similarly, the phase FBE base noise b2 in the interval (f1, f2) and the phase FBE base noise b3 in the interval [f2, f / 2].

[0072] Step 3: Continue waiting for a period of time to allow the well pressure to rise to the specified value. Open the casing valve and use DAS to collect the corresponding acoustic data. If the DAS amplitude data cannot find the suspected leak location at this time, proceed to Step 4; otherwise, skip Step 4. The pressure is based on the wellhead pressure. Use a wellhead pressure acquisition device to collect the wellhead pressure. After the pressure reaches P1, open the casing valve and perform DAS data acquisition. P1 needs to be set according to the actual wellbore conditions, taking into account the general pressure level of the gas well being measured and the amount of leakage in the tubing. For conventional gas wells, P1 can generally be set to 5 MPa, which can be adjusted upwards or downwards appropriately according to the actual wellbore conditions. In this embodiment, 5 MPa is used. Data acquisition continues throughout the process before and after the casing valve is opened.

[0073] Step 4: Close the casing valve and repeat Step 3, collecting acoustic data at various pressures until the DAS amplitude can distinguish the suspected leak location or the pressure cannot be increased further. Increase the pressure sequentially to P2, P3, P4, and P5, then open the casing valve until the DAS amplitude can distinguish the leak location or the wellhead pressure cannot be increased further. For P2, P3, P4, and P5, each pressure is increased by 20% from the previous increase. The criterion for distinguishing the leak location is that the leak location amplitude consistently exceeds a threshold, typically set to 5 times the baseline noise level in Step 2. If the amplitude remains relatively stable, there is no leak. The DAS continues collecting data. In this embodiment, the threshold is 30. A suspected leak location can be clearly distinguished after the pressure is increased to 12 MPa.

[0074] Step 5: Perform spectrum analysis on the DAS data collected at the highest pressure. Determine the leak location and type based on the frequency range of the DAS amplitude signal strength and DAS phase. The specific steps are as follows:

[0075] Step 5-1: Compare the collected amplitude data with a threshold. If the amplitude consistently exceeds the threshold, the location is considered a suspected leak location. If not, no leak is considered. The amplitude judgment threshold can be adjusted according to the basic noise level at the site, generally set to 5 times the basic noise level. The greater the pressure difference between the tubing and casing, the higher the threshold. In this embodiment, the threshold is 30. Suspected leak locations can be clearly distinguished after the pressure is increased to 12 MPa. (Appendix) Figure 4 The image shows the DAS amplitude at various locations in the wellbore when the pressure is 12 MPa in this embodiment. It is clear that the amplitudes at 445 meters and 1134 meters are high and exceed the amplitude threshold, therefore they are classified as suspected leak points. The excessive amplitude at the tail end is due to the fiber optic cable not being knotted and the tail end swaying.

[0076] Step 5-2: Perform FBE calculation on the phase data of the suspected leak locations identified in Step S5-1, dividing the frequency into three intervals: [0, f1], (f1, f2), and [f2, f / 2], where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to the leak, respectively, and are adjustable. Calculate the FBE values ​​for each frequency band of the signal within 10 minutes.

[0077] The frequency is divided into three intervals: [0, f1], (f1, f2), and [f2, f / 2]. This is because the leakage signal is mainly concentrated in the intermediate frequency (IF), therefore the FBE energy value is higher in the IF band, i.e., the energy is higher in the (f1, f2) band, while other energy bands have lower energy. In this embodiment, f1 and f2 are 20Hz and 500Hz, respectively. The FBE calculation formula is as follows:

[0078]

[0079] Where m is the number of points within the frequency range of the signal's FFT, and P is the FFT value corresponding to each frequency. The FFT window size is adjustable, typically for signals of durations such as 10s, 30s, 1min, and 2min. In FBE, the window size is n, measured in seconds. Therefore, within 10 minutes, there should be floor(600 / m) FBE values, where floor() represents rounding down. This embodiment uses a 10s window, calculating a total of 60 FBE values ​​within 10 minutes.

[0080] The FBE threshold in step 5-3 is related to the phase basis noise collected in step 2. Generally, the FBE threshold in each frequency band is 5 times the phase FBE basis noise in that frequency band.

[0081] In this embodiment, the FBE energy at well depths of 445 meters and 1134 meters was calculated when the pressure was 12 MPa. Based on the comparison of the energy values ​​in the three frequency bands with known thresholds, it was determined that the two suspected leakage locations in step 3 were indeed leaks, which were either due to tubing damage or poor sealing between tubing sections. The construction team was then guided to lift or repair the tubing.

[0082] Figure 5 This is a schematic diagram of the data processing flow of this solution. In this embodiment, actual tests were conducted at the gas storage well on-site according to the steps of the invention. After the tests were completed, the construction team was guided to lift or repair the oil pipe, and two oil pipe damage locations were indeed found, which matched the actual situation.

[0083] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A leak monitoring system for downhole tubing in gas injection wells, characterized in that, It includes an oil pipe (2) installed inside the production casing (1) and a packer (3) and a perforation (4) installed on the outer wall of the production casing (1); an optical fiber (5) is provided in the oil pipe (2), and a DAS (6) for collecting amplitude fundamental noise and phase fundamental noise is connected to one end of the optical fiber (5); and an oil pipe valve is also provided on the oil pipe (2).

2. A method for monitoring leaks in the downhole tubing of a gas injection well, characterized in that, The gas injection well downhole tubing leakage monitoring system according to claim 1 includes the following steps: Install the packer and perforation outside the production casing, install the optical fiber inside the tubing, inject gas into the tubing until a pressure differential is generated, then stop injecting gas, close the tubing valve and let it stand, and use DAS to obtain amplitude noise data and phase noise data of the tubing under stable conditions. When the pressure inside the well reaches the set pressure value, open the tubing valve and use DAS to collect the corresponding acoustic data. If the acoustic data indicates a suspected leak location, close the oil pipe valve and repeat the above steps to collect acoustic data at several pressures until the acoustic data amplitude distinguishes the suspected leak location or the pressure can no longer be increased. The acoustic data did not reveal any suspected leak location. Spectral analysis was performed on the acoustic and noise data collected at the highest pressure to determine the leak location and type.

3. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 2, characterized in that, The steps to obtain the amplitude and phase fundamental noise are as follows: Step 1: Average the amplitude data of the entire first frame to obtain a1. Calculate the FBE of the phase data of the entire first frame on [0, f1], (f1, f2), and [f2, f / 2] respectively, and average them to obtain (b). 11 ,b 21 ,b 31 ); where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage; Step 2: Perform the amplitude operation from Step 1 on each frame of amplitude data collected to obtain n amplitude mean data a1, a2…a n Where n is the number of amplitude frames acquired by DAS within 10 minutes; perform the phase operation in step 1 on each frame of phase data acquired within 10 minutes to obtain n sets of phase FBE mean data (b 11 ,b 21 ,b 31 ), (b 12 ,b 22 ,b 32 ...(b 1n ,b 2n ,b 3n ), where n is the number of phase frames acquired by DAS within 10 minutes; Step 3: For a1, a2…a n Sum and average to obtain the amplitude basis noise 'a', and for 'b'... 11 b 12 …b 1n By summing and averaging, we obtain the phase FBE base noise b1 in the interval [0, f1], and similarly, the phase FBE base noise b2 in the interval (f1, f2) and the phase FBE base noise b3 in the interval [f2, f / 2].

4. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 2, characterized in that, The length of the fiber optic cable is greater than the depth of the location to be monitored.

5. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 4, characterized in that, After the wellhead is lowered, the wellhead position is determined by tapping the wellhead and measuring the change in DAS amplitude. The length of the fiber optic cable at the wellhead is then calibrated to 0.

6. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 2, characterized in that, The methods for obtaining the leak location and leak type are as follows: The collected amplitude data is compared with a threshold. If the amplitude continuously exceeds the threshold, the location is considered a suspected leak location; if the amplitude does not continuously exceed the threshold, there is no leak at that location. The frequency is divided into three intervals: [0, f1], (f1, f2), [f2, f / 2], where f is the DAS pulse sampling frequency, and f1 and f2 are the lowest and highest frequencies corresponding to leakage. Calculate the FBE value of the signal in each frequency band within 10 minutes. If all FBE values ​​in the (f1, f2) frequency band are greater than the corresponding FBE threshold within 10 minutes, and the FBE values ​​in the other two frequency bands are less than the corresponding FBE threshold, then the location is determined to be a leakage location; otherwise, it is noise.

7. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 6, characterized in that, The threshold is adjusted based on the on-site basic amplitude noise data and is set to 5 times the amplitude noise data.

8. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 6, characterized in that, The FBE threshold is related to the phase noise data, and the FBE threshold in each frequency band is 5 times the phase noise data in that frequency band.

9. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 5, characterized in that, The calculation method for FBE is as follows: Where m is the number of points in the FFT frequency range of the signal, and P is the FFT value corresponding to each frequency.

10. The method for monitoring leakage in the downhole tubing of a gas injection well according to claim 2, characterized in that, The set pressure value is determined by the measured gas well pressure level and the leakage of the oil tubing.

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