An external anomaly monitoring system and method for high-sulfur gas wells

Abstract

This invention discloses an external anomaly monitoring system and method for high-sulfur gas wells. The system includes: a signal receiving device, which constructs multiple points at the well site where the gas well to be monitored is located. Each point is used to receive a first microseismic signal in real time. The first microseismic signal at each point is obtained after a second microseismic signal emitted by a target source propagates through the well site; an anomaly type identification device, which extracts the signal characteristic parameters of the continuous microseismic signal at each point over a specified time period to determine the anomaly type; and an anomaly area identification device, which determines one or more valid points that actually receive the second microseismic signal and their location distribution based on the first microseismic signals at the multiple points, thereby determining the current anomaly area. This invention achieves real-time monitoring, early warning, and location of external anomaly movement status of high-sulfur gas wells.

Description

Technical Field

[0001] This invention belongs to the field of safety monitoring of high-sulfur natural gas wells, and in particular relates to an external anomaly monitoring system and method for high-sulfur gas wells. Background Technology

[0002] With the continuous development of the national economy and the ongoing optimization of the energy structure, natural gas, as a clean and environmentally friendly high-quality energy source, has gradually occupied an important position in the energy structure. Simultaneously, natural gas consumption has shown a sustained and substantial upward trend. To ensure natural gas supply, my country has continuously increased its efforts in natural gas exploration and development in recent years, and has gradually developed natural gas blocks with high hydrogen sulfide content. Statistics show that my country's high-sulfide gas fields are mainly distributed in the densely populated and topographically complex Sichuan-Chongqing region. Given the highly toxic nature of hydrogen sulfide, leaks during extraction, gathering, transportation, and processing can lead to serious accidents.

[0003] First, existing technology provides a seismic wave-based underground intrusion monitoring system. This system utilizes seismic exploration principles to locate, identify, and judge underground intrusion behavior, effectively preventing illegal and criminal activities from underground. Furthermore, this monitoring system leverages pattern recognition theory to distinguish between various behaviors of moving objects and humans. By preprocessing and extracting features from the collected seismic wave signals and matching them with features in a feature database, it identifies potential intrusion behavior states and tracks their changing trends. Second, existing technology also proposes a microseismic sensing-based integrated land-air early warning system for key areas. This system is unaffected by terrain, region, or space. Combining ant colony optimization with the threat level, mobility, and UAV system reaction time of intrusion targets, it achieves real-time optimization of the early warning scheme, effectively identifying, tracking, repelling, and controlling intrusion targets. This extends the effective operating time of the entire system in unmanned mode, enabling continuous intelligent monitoring of key areas around the clock. It can also enhance the monitoring capabilities of key areas using existing wired video surveillance systems. In addition, existing technology also provides an intrusion monitoring device and system for field oil and gas pipelines. The device emits light signals to an optical fiber through a laser generator and transmits them to a photoelectric conversion device through an optical coupler. The photoelectric conversion device converts the light signals into electrical signals and sends them to the acquisition board. The acquisition board transmits the acquired signals to the main control board. The main control board identifies the signals and determines whether the monitored oil and gas pipeline has been vibrated or damaged, thereby realizing the detection of the pipeline status.

[0004] Currently, monitoring methods for production and safety accidents caused by external anomalies mainly rely on on-duty video surveillance or infrared camera identification. On-duty video surveillance requires significant manpower and resources, and its effectiveness is affected by factors such as the responsibility and attention of the personnel, making it prone to missed detections. Infrared cameras can detect abnormal heat sources but cannot accurately identify every intruder wearing specialized protective gear. Furthermore, in developing this invention, the inventors discovered that the aforementioned existing technologies all employ different principles for safety monitoring of specific locations, but they do not specifically address the external intrusion scenarios that high-sulfur gas wells may face, thus lacking specificity. Therefore, it is essential to research technologies for monitoring, providing early warnings, and locating intruders in the external environmental safety status of high-sulfur gas wells. Summary of the Invention

[0005] To address the aforementioned problems, this invention provides an external anomaly monitoring system for high-sulfur gas wells, comprising: a signal receiving device, which constructs multiple points at the well site where the gas well to be monitored is located, each point being used to receive a first microseismic signal in real time, the first microseismic signal at each point being obtained after a second microseismic signal emitted by a target source propagates through the well site; an anomaly type identification device, which extracts signal characteristic parameters of the continuous microseismic signal at each point over a specified time period to determine the anomaly type; and an anomaly area identification device, which determines one or more valid points that actually receive the second microseismic signal and their location distribution based on the first microseismic signals at the multiple points, thereby determining the current anomaly area.

[0006] Preferably, the plurality of points are evenly distributed on a circle centered on the center of the gas well to be monitored, wherein the position of each point is determined according to the optimal monitoring distance of each point.

[0007] Preferably, the optimal monitoring distance includes: the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance, wherein the optimal non-drilling theft monitoring distance / the optimal drilling theft monitoring distance is obtained by using micro-seismic sensors placed at any point in the well site to conduct walking tests / digging tests.

[0008] Preferably, the plurality of points are at least three points. If the well site where the gas well to be monitored is located is a rectangular well site, a four-point point arrangement method is adopted; or if the well site where the gas well to be monitored is located is a triangular well site, a three-point point arrangement method is adopted.

[0009] Preferably, the signal receiving device includes: multiple microseismic sensors respectively disposed at different locations, wherein the microseismic sensors are three-component microseismic sensors that meet specific technical parameter conditions, including: bandwidth of 1~240Hz; GNSS timing accuracy of + / -10μs; gain accuracy of 0.1%; and

[0010] The sampling interval is less than or equal to 4ms.

[0011] Preferably, the anomaly type identification device includes: a signal analysis unit, which is used to extract the reception time and amplitude information from the continuous microseismic signal at each point as the signal feature parameters, so as to obtain the amplitude change characteristics and signal reception time interval of each continuous microseismic signal; and an anomaly type generation unit, which is used to determine the current anomaly type based on the amplitude change characteristics and the signal reception time interval, wherein if the amplitude gradually increases, the current anomaly type is determined to be non-punch-hole theft, or if the amplitude remains unchanged and the signal reception time interval is the same, the current anomaly type is determined to be punch-hole theft.

[0012] Preferably, the anomaly area identification device includes: an anomaly area division unit, which is used to plan multiple sets of point combinations with different numbers and locations that have the ability to receive the second microseismic signal, and to match an anomaly occurrence area for each set of point combinations; and an anomaly area generation unit, which is used to identify the number and location of valid points that receive the second microseismic signal in real time based on the first microseismic signal of each point, determine the corresponding point combination, and retrieve the anomaly occurrence area that matches the current point combination as the current anomaly area.

[0013] Preferably, the external anomaly monitoring system further includes an anomaly tracking device, which is used to collect the identified anomaly areas in real time and determine the movement path of the anomaly areas according to the time of their occurrence, thereby tracking the anomaly situation.

[0014] Preferably, the abnormal area identification device is further used to calculate the coordinates of the current abnormal area when the number of points that actually receive the second microseismic signal is greater than or equal to 3, taking the center of the gas well to be monitored as the origin of the coordinates, using the distance between each effective point and the abnormal area, and the time difference between any two effective points receiving the microseismic signal, combined with the propagation distance of the second microseismic signal in the well site where the current gas well to be monitored is located, thereby accurately locating the current abnormal area.

[0015] Preferably, the anomaly area identification device includes: a propagation velocity calculation unit, which is used to deploy microseismic sensors at any two points in the well site to receive the first microseismic signal of the experimental target source, and to calculate the propagation velocity of the microseismic signal in the well site where the current gas well is located by using the signal reception time difference between each microseismic sensor and the distance between the experimental target source and each microseismic sensor, so as to obtain the propagation distance of the second microseismic signal in the well site where the current gas well is located.

[0016] Preferably, the propagation speed calculation unit is further used to calculate the distance difference between the experimental target source and the microseismic sensors at any two points, and to use the ratio between the distance difference and the signal reception time difference as the propagation speed.

[0017] Furthermore, this invention also proposes an external anomaly monitoring method for high-sulfur gas wells. This method utilizes the external anomaly monitoring system for high-sulfur gas wells described in this invention to monitor external anomalies. The method includes: constructing multiple points at the well site of the gas well to be monitored using a signal receiving device, such that each point can receive a first microseismic signal in real time. The first microseismic signal at each point is obtained after a second microseismic signal emitted by a target source propagates through the well site; extracting signal characteristic parameters of the continuous microseismic signal at each point over a specified time period using an anomaly type identification device to determine the anomaly type; and determining one or more valid points that actually received the second microseismic signal and their location distribution based on the first microseismic signals from the multiple points, thereby determining the current anomaly area.

[0018] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0019] This invention proposes an external anomaly monitoring system and method for high-sulfur gas wells. The system's signal receiving device constructs multiple points at the well site where the monitored gas well is located, and collects microseismic signals related to anomaly activities (e.g., intrusion by outsiders) at each point. An anomaly type identification device determines the anomaly type based on the characteristic parameters of the microseismic signals. An anomaly area identification device determines the current anomaly area based on the effective points and their location distribution of the actual collected microseismic signals. This invention proposes a reasonable and effective method for monitoring, early warning, and locating external anomalies in high-sulfur gas wells based on microseismic signals, effectively expanding the monitoring range for external anomalies in high-sulfur gas wells, and enabling the identification of anomaly types and the location of anomalies.

[0020] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims and drawings. Attached Figure Description

[0021] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0022] Figure 1This is a schematic diagram of the overall structure of an external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application.

[0023] Figure 2 This is a schematic diagram of the microseismic signal propagation of an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application.

[0024] Figure 3 This is a schematic diagram of the propagation speed test of the external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application.

[0025] Figure 4 This is a schematic diagram of the optimal monitoring distance test for an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application.

[0026] Figure 5 This is a schematic diagram of the four-point layout of the external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application.

[0027] Figure 6 This is a schematic diagram of the precise positioning of four points for an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application.

[0028] Figure 7 This is a schematic diagram of the three-point layout of the external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application.

[0029] Figure 8 This is a step diagram of an external anomaly monitoring method for high-sulfur gas wells according to an embodiment of this application. Detailed Implementation

[0030] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that, as long as there is no conflict, the various embodiments and features in the various embodiments of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0031] Furthermore, the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0032] With the continuous development of the national economy and the ongoing optimization of the energy structure, natural gas, as a clean and environmentally friendly high-quality energy source, has gradually occupied an important position in the energy structure. Simultaneously, natural gas consumption has shown a sustained and substantial upward trend. To ensure natural gas supply, my country has continuously increased its efforts in natural gas exploration and development in recent years, and has gradually developed natural gas blocks with high hydrogen sulfide content. Statistics show that my country's high-sulfide gas fields are mainly distributed in the densely populated and topographically complex Sichuan-Chongqing region. Given the highly toxic nature of hydrogen sulfide, leaks during extraction, gathering, transportation, and processing can lead to serious accidents.

[0033] First, existing technology provides a seismic wave-based underground intrusion monitoring system. This system utilizes seismic exploration principles to locate, identify, and judge underground intrusion behavior, effectively preventing illegal and criminal activities from underground. Furthermore, this monitoring system leverages pattern recognition theory to distinguish between various behaviors of moving objects and humans. By preprocessing and extracting features from the collected seismic wave signals and matching them with features in a feature database, it identifies potential intrusion behavior states and tracks their changing trends. Second, existing technology also proposes a microseismic sensing-based integrated land-air early warning system for key areas. This system is unaffected by terrain, region, or space. Combining ant colony optimization with the threat level, mobility, and UAV system reaction time of intrusion targets, it achieves real-time optimization of the early warning scheme, effectively identifying, tracking, repelling, and controlling intrusion targets. This extends the effective operating time of the entire system in unmanned mode, enabling continuous intelligent monitoring of key areas around the clock. It can also enhance the monitoring capabilities of key areas using existing wired video surveillance systems. In addition, existing technology also provides an intrusion monitoring device and system for field oil and gas pipelines. The device emits light signals to an optical fiber through a laser generator and transmits them to a photoelectric conversion device through an optical coupler. The photoelectric conversion device converts the light signals into electrical signals and sends them to the acquisition board. The acquisition board transmits the acquired signals to the main control board. The main control board identifies the signals and determines whether the monitored oil and gas pipeline has been vibrated or damaged, thereby realizing the detection of the pipeline status.

[0034] Currently, monitoring methods for production and safety accidents caused by external anomalies mainly rely on on-duty video surveillance or infrared camera identification. On-duty video surveillance requires significant manpower and resources, and its effectiveness is affected by factors such as the responsibility and attention of the personnel, making it prone to missed detections. Infrared cameras can detect abnormal heat sources but cannot accurately identify every intruder wearing specialized protective gear. Furthermore, in developing this invention, the inventors discovered that the aforementioned existing technologies all employ different principles for safety monitoring of specific locations, but they do not specifically address the external intrusion scenarios that high-sulfur gas wells may face, thus lacking specificity. Therefore, it is essential to research technologies for monitoring, providing early warnings, and locating intruders in the external environmental safety status of high-sulfur gas wells.

[0035] Therefore, to address the aforementioned problems, this invention proposes an external anomaly monitoring system and method for high-sulfur gas wells. The system's signal receiving device constructs multiple points at the well site where the monitored gas well is located, and collects microseismic signals related to anomaly activities (e.g., intrusion by outsiders) at each point. Anomaly type identification device determines the anomaly type based on the characteristic parameters of the microseismic signals. Anomaly area identification device determines the current anomaly area based on the effective points and their location distribution of the actual collected microseismic signals. This invention proposes a reasonable and effective method for monitoring, early warning, and locating external anomalies in high-sulfur gas wells based on microseismic signals, effectively expanding the monitoring range for external anomalies in high-sulfur gas wells and enabling the identification of anomaly types and the location of anomalies.

[0036] Example 1

[0037] Figure 1 This is a schematic diagram of the overall structure of an external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application. The following is in conjunction with... Figure 1 The structure of the external anomaly monitoring system for high-sulfur gas wells described in this invention will be explained in detail.

[0038] In this embodiment, the external anomaly monitoring system for high-sulfur gas wells includes at least: a signal receiving device 11, an anomaly type identification device 12, and an anomaly area identification device 13. The signal receiving device 11 constructs multiple points at the well site where the gas well to be monitored is located. Each point is used to receive a first microseismic signal in real time. The first microseismic signal at each point is obtained after a second microseismic signal emitted by a target source propagates through the well site. The anomaly type identification device 12 extracts the signal characteristic parameters of the continuous microseismic signal at each point constructed by the signal receiving device 11 over a specified time period, thereby determining the anomaly type. The anomaly area identification device 13 determines one or more valid points that actually receive the second microseismic signal and their location distribution based on the first microseismic signals from the multiple points constructed by the signal receiving device 11, thereby determining the current anomaly area.

[0039] The signal receiving device 11 constructs multiple points at the well site where the gas well to be monitored is located. Each point is used to receive a first micro-vibration signal in real time. The first micro-vibration signal at each point is obtained after the second micro-vibration signal emitted by the target source propagates through the well site. To solve the problems of blind spots and the large influence of on-duty personnel on gas well safety monitoring methods that use personnel on duty for video surveillance and infrared camera identification in practical applications, this invention realizes real-time monitoring of the external anomaly status of high-sulfur gas wells based on micro-vibration signals related to abnormal activities. Specifically, the signal receiving device 11 constructs multiple points at the well site where the gas well to be monitored is located, and receives micro-vibration signals related to the occurrence of external anomalies (e.g., intrusion by outsiders) at each point in real time, thereby realizing real-time monitoring of the external anomaly status of high-sulfur gas wells based on the received micro-vibration signals. Among them, when an external anomaly occurs, the synchronous micro-vibration signal generated by the anomaly is the second micro-vibration signal emitted by the target source. This second micro-vibration signal is received by the corresponding point after propagating through the well site, and the micro-vibration signal received by the corresponding point is the first micro-vibration signal.

[0040] Any signal attenuates over time during propagation. Furthermore, high-sulfur gas wells in my country are mainly distributed in the Sichuan-Chongqing region and the Ordos Basin, where the surface layers are primarily soft soil and dense sand, respectively. The propagation speed and distance of microseismic signals vary under different surface characteristics. Therefore, before the signal receiving device 11 constructs multiple points at the well site of the gas well to be monitored, it is necessary to determine the optimal monitoring range of the selected microseismic sensor under different surface conditions. Thus, this embodiment first determines the surface characteristics of the well site where the gas well is located, and then obtains the optimal monitoring distance of the microseismic sensor under the current surface characteristics. Meanwhile, my country's high-sulfur gas fields are mainly distributed in the Sichuan-Chongqing region, which has complex terrain and dense population. Gas wells are mainly located on the mountainside or mountaintop, and only dedicated roads lead to the well sites. Because the well sites are surrounded by clear boundaries and walls, there is almost no situation where vehicles rush in or large excavators drive in to cause damage. However, the surrounding dense population and large amount of farmland mean that there are only two types of abnormal activities at the gas well sites: people approaching the gas wells to steal natural gas through the sampling port at the wellhead (i.e., non-drilling theft) and people digging through the soil around the wellhead to drill holes in the pipeline to steal natural gas (i.e., drilling theft).

[0041] Furthermore, the optimal monitoring distance of this invention includes an optimal non-drilling theft monitoring distance and an optimal drilling theft monitoring distance. The optimal non-drilling theft monitoring distance / optimal drilling theft monitoring distance is obtained by conducting walking / digging tests using a microseismic sensor placed at any point in the well site. Specifically, in this embodiment, a microseismic sensor (the same as the one actually used to receive microseismic signals) for testing the optimal monitoring distance is buried below the surface at any location in the well site where the gas well to be monitored is located, according to a first specified burial depth. Then, multiple test distances are set, and corresponding test points are determined according to each test distance, such that the distance between each test point and the microseismic sensor currently used for testing the optimal monitoring distance meets the set test distance. Finally, by walking in place and digging with a hoe at each test point, data is collected as follows: Figure 4 The microseismic signal from the stationary stepping test shown on the left and the microseismic signal from the hoe digging test shown on the right are ( Figure 4 This is a schematic diagram illustrating the optimal monitoring distance test for an external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application. Specifically, when the test microseismic signal is clear and the waveform is distinct, clearly distinguishing the instantaneous occurrence of stationary stepping and digging with a pickaxe, the corresponding test distance is determined to be the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance for this surface condition, as shown in Table 1.

[0042] Table 1 Optimal Monitoring Distance

[0043]

[0044] In one specific embodiment of this application, the first designated burial depth is preferably 30 cm, and the test distance is preferably 5 m, 10 m, 20 m, 30 m, and 50 m. It should be noted that this invention does not specifically limit the first designated burial depth and test distance; those skilled in the art can set these based on the signal acquisition sensitivity, anomaly type, and surface characteristics of the selected microseismic sensor used to receive the microseismic signal.

[0045] Furthermore, the signal receiving device 11 is constructed with multiple points evenly distributed on a circle centered on the center of the gas well to be monitored. The position of each point is determined according to the optimal monitoring distance for that point. Specifically, based on the aforementioned analysis, it is known that there are only two types of anomalies at the gas well site: personnel approaching the gas well to steal natural gas through the sampling port at the wellhead (i.e., non-drilling theft) and personnel digging through the soil around the wellhead to drill holes in the pipeline to steal natural gas (i.e., drilling theft). In other words, the anomalies caused by theft will inevitably surround the gas well to be monitored. Therefore, in this embodiment, multiple points are evenly distributed on a circle centered on the center of the gas well to be monitored, effectively ensuring comprehensive monitoring of anomalies. In a specific embodiment of this application, it is assumed that the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance are a and b, respectively. Generally speaking, there is a relationship between the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance: a < b < 2a. Therefore, in this embodiment, the location of each point is determined to be 0.5a away from the wellhead of the gas well to be monitored, so that each point has the ability to fully monitor the anomalies around the well. In addition, since the multiple points constructed by the signal receiving device 11 all have the ability to fully monitor the anomalies around the well, the reliability of the monitoring of the anomalies around the gas well to be monitored is effectively improved.

[0046] The multiple points described in this invention refer to at least three points. If the well site where the gas well to be monitored is located is a rectangular well site, a four-point point arrangement method is used; or if the well site where the gas well to be monitored is located is a triangular well site, a three-point point arrangement method is used. In the embodiments of this application, in the four-point point arrangement method, the lines connecting adjacent points to the center of the gas well form a 45° angle.

[0047] Furthermore, the signal receiving device 11 includes multiple microseismic sensors respectively disposed at different locations. In practical applications, the synchronous microseismic signals generated by anomalies are generally weak and have a low frequency range, so it is necessary to select low-frequency microseismic sensors with high sensitivity to meet the acquisition requirements of the target microseismic signals. In this embodiment, multiple microseismic sensors are disposed at different locations, with one microseismic sensor at each location. The microseismic sensors are three-component microseismic sensors, and the three-component microseismic sensors meet the following specific technical parameter conditions, thereby enabling the selected three-component microseismic sensors to acquire the target microseismic signals. Among them, the specific technical parameter conditions include: bandwidth of 1~240Hz; GNSS timing accuracy of + / -10μs; gain accuracy of 0.1%; and sampling interval less than or equal to 4ms.

[0048] The anomaly type identification device 12 of the present invention is used to extract the signal characteristic parameters of the continuous microseismic signal of each point during a specified time period, thereby determining the anomaly type. Figure 2This is a schematic diagram of microseismic signal propagation in an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application. Figure 2 As shown, in practical applications, both non-drilling theft related to personnel movement and drilling theft related to personnel digging exert forces on the ground surface, generating vibrations and forming a second microseismic signal. This second microseismic signal then propagates to a distance, forming a first microseismic signal received by the signal receiving device 11, which is then captured by the microseismic sensor buried around the well to be monitored. When personnel walk, their footsteps interact with the ground surface, acting as a point source of vibration. As personnel move, under the condition of constant walking speed, the amplitude of the first microseismic signal gradually increases. However, the location and speed of manual digging are relatively fixed, so the amplitude and time interval of the first microseismic signal are relatively fixed, and the amplitude is significantly higher than that of personnel walking under the same distance conditions. Therefore, the anomaly type identification device 12 of this invention obtains the amplitude change trend and the change trend of the receiving time interval of each microseismic signal by extracting the signal characteristic parameters of the continuous microseismic signal at each point within a specified time period, thus achieving accurate identification of the anomaly type.

[0049] Furthermore, the anomaly type identification device 12 includes a signal analysis unit and an anomaly type generation unit. The signal analysis unit extracts the reception time and amplitude information from the continuous microseismic signals at each location as signal feature parameters to obtain the amplitude variation characteristics and signal reception time interval of each continuous microseismic signal. The anomaly type generation unit determines the current anomaly type based on the amplitude variation characteristics and signal reception time interval. Specifically, the signal analysis unit extracts the reception time and amplitude information from the continuous microseismic signals at each location as signal feature parameters, calculates the reception time interval between adjacent signals using each reception time, and calculates the amplitude difference between adjacent signals using the amplitude information of each signal, thereby obtaining the amplitude variation characteristics and signal reception time interval of each continuous microseismic signal. At this time, the anomaly type generation unit determines the current anomaly type based on the amplitude variation characteristics and signal reception time interval calculated by the signal analysis unit. As can be seen from the above analysis, if the amplitude of the continuous microseismic signal gradually increases, the current anomaly type is determined to be non-punch-hole theft; or if the amplitude of the continuous microseismic signal remains unchanged and the time interval between each signal reception is the same, the current anomaly type is determined to be punch-hole theft.

[0050] Furthermore, the anomaly area identification device 13 is used to determine one or more valid points that actually received the second microseismic signal and their location distribution based on the first microseismic signal from multiple points, thereby determining the current anomaly area. After the second microseismic signal begins to propagate, due to the different distances between the target source and different points, there may be one or more points that cannot receive the first microseismic signal. That is to say, the number and location distribution of points that receive the first microseismic signal are related to the location of the target source. Therefore, in this embodiment, points that receive the first microseismic signal belonging to the same target source (one or more points that actually receive the second microseismic signal) are taken as valid points, thus achieving the purpose of determining the current anomaly area based on one or more valid points that actually receive the second microseismic signal and their location distribution.

[0051] The anomaly area identification device 13 includes an anomaly area division unit and an anomaly area generation unit. The anomaly area division unit plans multiple sets of point combinations with different numbers and locations capable of receiving second microseismic signals, and matches anomaly occurrence areas for each set of point combinations. The anomaly area generation unit identifies the number and location of valid points receiving the second microseismic signal in real time based on the first microseismic signal of each point, determines the corresponding point combination, and retrieves the anomaly occurrence area matching the current point combination as the current anomaly area. In this embodiment, the anomaly area division unit plans multiple sets of point combinations with different numbers and locations capable of receiving second microseismic signals, and matches anomaly occurrence areas for each set of point combinations, thus obtaining a mapping relationship between point combinations and anomaly occurrence areas. Furthermore, the anomaly area generation unit identifies the number and location of valid points that receive the second microseismic signal in real time based on the points that receive the first microseismic signal, determines the actual point combination, and then uses the mapping relationship between the point combination and the anomaly occurrence area to retrieve the anomaly occurrence area that matches the current actual point combination. This anomaly occurrence area is the current anomaly area.

[0052] Next, refer to Figure 5 Table 2, taking the four-point layout method as an example, provides a detailed explanation of the functions of the dynamic area division unit and the dynamic area generation unit. Figure 5 This is a schematic diagram of the four-point layout of the external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application.

[0053] Table 2. Mapping relationship between point combination and anomaly occurrence area in the embodiment.

[0054]

[0055] In the process of planning multiple sets of point combinations with different numbers and locations capable of receiving second microseismic signals within the anomaly area delineation unit, and matching the anomaly occurrence area for each set of point combinations, reference is made to... Figure 5 Based on the four-point layout method, the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance are denoted as a and b, respectively, thus forming the following four monitoring barriers around the well to be monitored: 0~0.5a, 0.5a~a, a~1.5a and 1.5a~0.5a+b.

[0056] When the distance from the gas wellhead to the abnormal movement is greater than 0.5a+b, the distance is too far to steal natural gas by drilling holes in the surface pipeline (i.e., drilling is not possible), and in this case, drilling theft does not need to be monitored. When the distance from the gas wellhead to the abnormal movement is greater than or equal to 1.5a (located outside or at the edge of area C or D), the distance from the wellhead is too far to steal natural gas through the wellhead sampling port (i.e., non-drilling theft), and in this case, non-drilling theft does not need to be monitored.

[0057] When the distance from the gas wellhead to the abnormality is 1.5a to 0.5a+b (within area E or F), it means that the area has entered the monitoring zone for drilling and theft. Under the condition that there is a microseismic sensor to realize monitoring and early warning (the current combination of points with the ability to receive the second microseismic signal is a combination of points including only one microseismic sensor), it means that the personnel are conducting exploratory digging in area E or F, that is, the area where the abnormality occurred is area E or area F.

[0058] When the distance between the abnormality and the wellhead is less than 1.5a (within area A, B, C, or D), it is clear that the area has entered the monitoring zone for drilling and theft. Under the condition that there are three or more microseismic sensors to achieve monitoring and early warning (the current combination of points capable of receiving the second microseismic signal is a combination of points including three or more microseismic sensors), it indicates that personnel are conducting exploratory digging in area A, B, C, or D, that is, the area where the abnormality occurred is area A, B, C, or D.

[0059] When the distance from the gas wellhead to the abnormal movement is 1a to 1.5a (in area C or D), it has entered the effective monitoring range for non-drilling theft. Under the condition that one microseismic sensor can provide monitoring and early warning (the current combination of points capable of receiving a second microseismic signal is a combination of points including only one microseismic sensor), it indicates that personnel have entered area D from the four directions of southwest, northwest, southeast, or northeast. Under the condition that two microseismic sensors can provide monitoring and early warning (the current combination of points capable of receiving a second microseismic signal is a combination of points including two microseismic sensors), it indicates that personnel have entered area C from the four directions of due south, due north, due east, or due west.

[0060] If the distance from the gas wellhead to the abnormal movement is between 0.5a and 1a, most of the intruder's activities will be completed within area B. Under the condition that three microseismic sensors provide monitoring and early warning (the current combination of points capable of receiving a second microseismic signal includes three microseismic sensors), this indicates that the intruder has entered area D. Alternatively, a small amount of the intruder's activities will be completed within area C in the four directions of east, west, south, or north. Under the condition that two microseismic sensors provide monitoring and early warning (the current combination of points capable of receiving a second microseismic signal includes two microseismic sensors), this indicates that the intruder has entered area C.

[0061] If the distance between the gas wellhead and the abnormal movement is between 0 and 0.5a, and there are four microseismic sensors for monitoring and early warning (the current combination of points capable of receiving the second microseismic signal is a combination of points including four microseismic sensors), it indicates that personnel are already in area A.

[0062] In summary, the four-point location arrangement method described in this invention effectively increases the monitoring range compared to monitoring methods that only use a single microseismic sensor (the diameter of the monitoring range for drilling and theft is increased from a to 1.5a; the diameter of the monitoring range for non-drilling and theft is increased from b to 0.5a+b). Furthermore, when the current location combination includes one or more locations, it achieves regional positioning within the entire monitoring range of the gas well to be monitored.

[0063] Furthermore, the external anomaly monitoring system of this invention also includes an anomaly tracking device. The anomaly tracking device is used to collect data on the identified anomaly areas in real time and determine the movement path of the anomaly areas according to the time of their occurrence, thereby tracking the anomaly. The four-point location arrangement method of this invention also roughly locates the anomaly across the entire area by dividing the area, the number of sensor alarms (the number of effective points), and the location of the alarm sensors (the location of the effective points), and then determines its movement route. The anomaly tracking device collects data on the identified anomaly areas in real time and generates a movement route map related to the anomaly according to the time of its occurrence, thereby determining the movement path of the anomaly areas and achieving the purpose of tracking the anomaly. Therefore, this invention, based on area positioning within the entire monitoring range of the gas well to be monitored, achieves effective tracking of the location and movement route of anomalies.

[0064] Furthermore, based on the area positioning achieved across the entire monitoring range of the gas well to be monitored when the current point combination includes one or more points, the anomaly area identification device 13 of the present invention is also used to calculate the coordinates of the current anomaly area when the number of points that actually receive the second microseismic signal is greater than or equal to 3, using the center of the gas well to be monitored as the coordinate origin, utilizing the distance between each effective point and the anomaly area, and the time difference between any two effective points receiving the microseismic signal, combined with the propagation distance of the second microseismic signal in the well site where the current gas well to be monitored is located, thereby accurately locating the current anomaly area.

[0065] In practical applications, one or two valid points are insufficient for precise location of a specific point. However, three or more valid points (i.e., the number of points that actually receive the second microseismic signal is greater than or equal to three) can achieve precise location of external anomalies. In other words, location can be achieved when the anomaly type is punching and the anomaly location is in area A, B, C, or D; or when the anomaly type is non-punching and the anomaly location is in area A or B. Figure 6 This is a schematic diagram illustrating the precise positioning of four points in an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application. (Refer to...) Figure 6 Given that the distance between the effective points and the wellhead of the gas well to be monitored is 0.5a, the coordinates of the three effective points are then marked with the center of the gas well as the origin. , The coordinates of the current abnormal position are marked as ( x , y The system calculates the coordinates of the current location of the anomaly using the following expression, achieving precise location identification. Furthermore, based on the coordinate changes matching the obtained location results, the system accurately determines the movement route, enabling targeted control measures.

[0066] (1)

[0067] (2)

[0068] in, L 1. L 2 and L 3 represents the distance between the location of the change and each valid point. V This indicates the propagation distance of the microseismic signal under current surface conditions. The time differences between valid locations for signal acquisition are represented by , and 'a' represents the optimal non-perforation detection distance. t 1. t 2 and t 3 represents the signal acquisition time at different valid locations. x The x-coordinate represents the location of the change. yThe vertical coordinate represents the location of the change.

[0069] In one specific embodiment of this application, if the current anomaly is located in the overlapping monitoring area of ​​four valid points, the three valid points that receive the strongest micro-seismic signals can be selected to accurately locate the current anomaly.

[0070] Furthermore, the anomaly area identification device 13 includes a propagation velocity calculation unit. This unit is used to deploy microseismic sensors at any two points in the well site to receive the first microseismic signal from the experimental target source. It then uses the signal reception time difference between the microseismic sensors and the distance between the experimental target source and each microseismic sensor to calculate the propagation velocity of the microseismic signal in the well site where the gas well to be monitored is located, thus obtaining the propagation distance of the second microseismic signal in the same well site. The dimensions of a single well site are typically 30m x 40m, with the gas well located at the center of the well site. Figure 3 This is a schematic diagram illustrating the propagation velocity test of an external anomaly monitoring system for high-sulfur gas wells, according to an embodiment of this application. (Refer to...) Figure 3 In one specific embodiment of this application, two microseismic sensors (the same as those actually used to receive microseismic signals) for receiving the first microseismic signal from the experimental target source are buried below the surface at any two points in the well site where the gas well to be monitored is located, according to a second specified burial depth. Then, at point 1, a red brick is released at a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick is in vertical contact with the ground, and the signal reception time difference between the two sensors is calculated. Finally, using the signal reception time difference and the distance between the experimental target source (the position where the brick contacts the ground) and each microseismic sensor, the propagation speed of the microseismic signal in the well site where the gas well to be monitored is calculated (as mentioned above, in this embodiment, the microseismic signal propagating in the well site where the gas well to be monitored is used as the second microseismic signal, so the propagation speed here is the propagation speed of the second microseismic signal), to obtain the propagation distance of the second microseismic signal in the current well site where the gas well to be monitored is located.

[0071] Continue to refer to Figure 3 In one specific embodiment of this application, the propagation velocity of the microseismic signal is measured at points 2 to 6 respectively, and the average value of the results of the 6 tests is taken as the propagation velocity of the microseismic signal in the well site where the gas well to be monitored is located, thereby effectively ensuring the reliability of the propagation velocity calculation results.

[0072] In one specific embodiment of this application, the second designated burial depth is preferably 30 cm, and the distance between any two points is preferably 40 m. It should be noted that the present invention does not specifically limit the second designated burial depth and the distance between the two points, and those skilled in the art can set them according to the signal acquisition sensitivity, anomaly type, and surface characteristics of the microseismic sensor actually used to receive microseismic signals.

[0073] Furthermore, the propagation speed calculation unit is also used to calculate the distance difference between the experimental target source and the microseismic sensors at any two points (the difference in distance between the two sensors and the ground where the bricks fell), and the ratio between the distance difference and the signal reception time difference is used as the propagation speed.

[0074] In addition, the location of monitoring points can be adjusted based on factors such as the shape of the gas well site, major anomalies, and investment budget. If the monitoring budget is insufficient, the gas well site is triangular, or the anomaly pattern is singular, a method such as... Figure 7 The three-point layout method shown ( Figure 7 (This is a schematic diagram of the three-point layout of an external anomaly monitoring system for high-sulfur gas wells according to an embodiment of this application) to effectively reduce monitoring costs. In this case, if the anomaly is in area B or C, a rough location of the area can be performed; if the anomaly is in area A, a precise location can be performed.

[0075] Example 2

[0076] In one specific embodiment of this application, the gas well to be monitored is located in a rectangular well site area in Sichuan Province. Sichuan experiences heavy rainfall during the flood season, and the surface soil is predominantly loose.

[0077] Next, following the four-point layout method described in Example 1, four points were constructed at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the area around the gas wellhead was selected around the well site. Two microseismic sensors were buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick was released from a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick was in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal was recorded. The propagation velocity of the microseismic signal was calculated as the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal was measured at points 2 to 6, and the measurement results are shown in Table 3. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0078] Table 3. Propagation speed measurement results of Example 2

[0079]

[0080] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Microseismic signals were collected by stepping in place and digging with a hoe at distances of 5m, 10m, 20m, 30m, and 50m from the sensor. After testing, the optimal non-drilling monitoring distance for this type of ground condition was determined to be 30m, and the optimal drilling monitoring distance was determined to be 50m.

[0081] Furthermore, according to Figure 5 The point distribution shown involves symmetrically shallowly burying four microseismic sensors at a 45° angle around the wellhead of the gas well to be monitored. The distance between the microseismic sensors and the wellhead is 15m, thus forming four monitoring barriers around the well: 0~15m, 15~30m, 30~45m, and 45m~65m. The mapping relationships between anomaly types and anomaly occurrence areas, as well as the mapping relationships between point combinations and anomaly occurrence areas, are obtained as shown in Tables 4 and 5.

[0082] Table 4. Mapping relationship between anomaly type and anomaly occurrence area in Example 2

[0083]

[0084] Table 5. Mapping relationship between point combinations and anomaly occurrence areas in Example 2

[0085]

[0086] Finally, according to the precise location conditions and location method of the abnormal position described in Example 1, when the abnormal position is 40m away from the wellhead during drilling and theft, the current abnormal position can be accurately located, and the movement route can be accurately identified through coordinate changes, thereby enabling targeted control.

[0087] Example 3

[0088] In one specific embodiment of this application, the gas well to be monitored is located in a rectangular well site area in Sichuan Province.

[0089] Next, following the four-point layout method described in Example 1, four points were constructed at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the area around the gas wellhead was selected around the well site. Two microseismic sensors were buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick was released from a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick was in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal was recorded. The propagation velocity of the microseismic signal was calculated as the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal was measured at points 2 to 6, and the measurement results are shown in Table 6. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0090] Table 6. Propagation speed measurement results in Example 3

[0091]

[0092] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Microseismic signals were collected by stepping in place and digging with a hoe at distances of 5m, 10m, 20m, 30m, 50m, 80m, and 100m from the sensor. After testing, the optimal non-drilling monitoring distance for this type of ground condition was determined to be 30m, and the optimal drilling monitoring distance was determined to be 50m.

[0093] Furthermore, according to Figure 5 The point distribution shown involves symmetrically shallowly burying four microseismic sensors at a 45° angle to the wellhead of the gas well to be monitored. The distance between the microseismic sensors and the wellhead is 15m, thus forming four monitoring barriers around the well: 0~15m, 15~30m, 30~45m, and 45m~65m. The mapping relationship between the anomaly type and the anomaly occurrence area, as well as the mapping relationship between the point combination and the anomaly occurrence area, are obtained as shown in Tables 7 and 8.

[0094] Table 7. Mapping relationship between anomaly type and anomaly occurrence area in Example 3

[0095]

[0096] Table 8. Mapping relationship between point combinations and anomaly occurrence areas in Example 3

[0097]

[0098] Finally, according to the precise location conditions and location method of the abnormal position described in Example 1, when the abnormal position is 20m away from the wellhead for non-drilling theft, the current abnormal position can be accurately located, and the movement route can be accurately identified through coordinate changes, thereby enabling targeted control.

[0099] Example 4

[0100] In one specific embodiment of this application, the gas well to be monitored is located in a rectangular well site area in the Ordos region. The Ordos region is located in a desert, with the surface mainly consisting of dense sand. The terrain in the Ordos region is flat, and the wells are often located within the desert with no surrounding obstructions. Since the well site is surrounded by clear boundaries and walls, there is almost no possibility of vehicles rushing in or large excavating machinery entering and causing damage. Therefore, the abnormal movement types of vehicle movement and mechanical excavation can be disregarded. In other words, the gas well site only has two types of abnormal movement: personnel approaching the gas well and stealing natural gas through the sampling port at the wellhead (i.e., non-drilling theft) and personnel digging through the soil around the wellhead to drill holes in the pipeline to steal natural gas (i.e., drilling theft).

[0101] Next, following the four-point layout method described in Example 1, four points were constructed at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the area around the gas wellhead was selected around the well site. Two microseismic sensors were buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick was released from a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick was in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal was recorded. The propagation velocity of the microseismic signal was calculated as the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal was measured at points 2 to 6, and the measurement results are shown in Table 9. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0102] Table 9. Propagation speed measurement results of Example 4

[0103]

[0104] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Microseismic signals were collected by stepping in place and digging with a hoe at distances of 5m, 10m, 15m, 20m, 25m, 30m, 35m, 40m, 50m, 55m, 60m, 65m, 70m, 75m, and 80m from the sensor. After testing, the optimal non-drilling monitoring distance for the microseismic sensor under these surface conditions was found to be 40m, and the optimal drilling monitoring distance was found to be 65m.

[0105] Furthermore, according to Figure 5 The point distribution shown involves symmetrically shallowly burying four microseismic sensors at a 45° angle around the wellhead of the gas well to be monitored. The distance between the microseismic sensors and the wellhead is 15m, thus forming four monitoring barriers around the well: 0~20m, 20~40m, 40~60m, and 60m~85m. The mapping relationships between anomaly types and anomaly occurrence areas, as well as the mapping relationships between point combinations and anomaly occurrence areas, are obtained as shown in Tables 10 and 11.

[0106] Table 10 Mapping relationship between anomaly type and anomaly occurrence area in Example 4

[0107]

[0108] Table 11 Mapping relationship between the four point combinations in Example 4 and the areas where anomalies occur

[0109]

[0110] Finally, according to the precise location conditions and methods for the abnormal position described in Example 1, when drilling to steal at a distance of 80m from the wellhead, a rough location of the current abnormal position can be achieved, but a precise location cannot be achieved.

[0111] Example 5

[0112] In one specific embodiment of this application, the gas well to be monitored is located in a rectangular well site area in the Ordos region.

[0113] Next, following the four-point layout method described in Example 1, four points were constructed at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the area around the gas wellhead was selected around the well site. Two microseismic sensors were buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick was released from a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick was in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal was recorded. The propagation velocity of the microseismic signal was calculated as the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal was measured at points 2 to 6, and the measurement results are shown in Table 12. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0114] Table 12 Propagation speed measurement results of Example 5

[0115]

[0116] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Microseismic signals were collected by stepping in place and digging with a hoe at distances of 5m, 10m, 15m, 20m, 25m, 30m, 35m, 40m, 50m, 55m, 60m, 65m, 70m, 75m, and 80m from the sensor. After testing, the optimal non-drilling monitoring distance for the microseismic sensor under these surface conditions was found to be 40m, and the optimal drilling monitoring distance was found to be 65m.

[0117] Furthermore, according to Figure 5 The point distribution shown involves symmetrically shallowly burying four microseismic sensors at a 45° angle to the wellhead of the gas well to be monitored. The distance between the microseismic sensors and the wellhead is 20m, thus forming four monitoring barriers around the well: 0~20m, 20~40m, 40~60m, and 60m~85m. The mapping relationships between anomaly types and anomaly occurrence areas, as well as the mapping relationships between point combinations and anomaly occurrence areas, are obtained as shown in Tables 13 and 14.

[0118] Table 13 Mapping relationship between anomaly type and anomaly occurrence area in Example 5

[0119]

[0120] Table 14 Mapping relationship between point combination and anomaly occurrence area in Example 5

[0121]

[0122] Finally, according to the precise location conditions and methods described in Example 1, when the anomaly is 50m away from the wellhead without drilling for illegal activities, a rough location of the current anomaly can be achieved. As the anomaly continues to approach the wellhead, if the direction of movement is due east, due west, due south, or due north, it will move from area C to area A after moving 30m, at which point precise location can be achieved; if the direction of movement is southwest, northwest, southeast, or northeast, it will enter area B, and precise location can also be achieved.

[0123] Example 6

[0124] In one specific embodiment of this application, the gas well to be monitored is located in the triangular well site area of ​​Sichuan Province. Well sites in this area are usually located on mountaintops with no farmland around them, which can largely rule out pipeline damage caused by human cultivation or Taoist priests. Therefore, after analysis, the most critical anomaly type is identified as human movement to the wellhead to steal gas (not by drilling).

[0125] Next, according to Figure 7The three-point layout method shown constructs three points at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the wellhead is selected around the well site. Two microseismic sensors are buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick is released from a height of 50cm above the ground, ensuring the maximum surface area of ​​the brick is in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal is recorded. The propagation velocity of the microseismic signal is the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal is measured at points 2 to 6, and the measurement results are shown in Table 15. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0126] Table 15 Propagation speed measurement results of Example 6

[0127]

[0128] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Steps were taken at distances of 5m, 10m, 20m, 30m, 50m, 80m, and 100m from the sensor, and corresponding microseismic signals were collected. After testing, the optimal non-drilling monitoring distance for this type of ground surface condition was determined to be 30m.

[0129] Furthermore, following the point distribution method described in Example 1, three microseismic sensors are shallowly buried around the wellhead of the gas well to be monitored, forming an equilateral triangle with the three sensors as vertices. The distance between the microseismic sensors and the wellhead is 15m, thereby forming three triangular monitoring barriers around the well to be monitored, and obtaining the mapping relationship between the point combination and the area where the anomaly occurred as shown in Table 16.

[0130] Table 16 Mapping Relationship between Point Combinations and Anomaly Occurrence Areas in Example 6

[0131]

[0132] Finally, according to the precise location conditions and methods for abnormal movement described in Example 1, when the abnormal movement occurs 10m from the wellhead without drilling, and personnel are in area A, three sensors will simultaneously monitor and issue warnings. The following expression can be used to achieve precise location of the current abnormal movement, and the movement route can be accurately identified through coordinate changes, thereby enabling targeted control:

[0133] (3)

[0134] (4)

[0135] (5)

[0136] Where c represents the distance between the sensors.

[0137] Example 7

[0138] In one specific embodiment of this application, the gas well to be monitored is located in the triangular well site area of ​​the Ordos region. Well sites in this area are usually located on mountaintops, with no farmland around them, which can largely rule out pipeline damage caused by human land reclamation or Taoist priests. Therefore, after analysis, drilling and theft were identified as the most critical type of anomaly.

[0139] Next, following the three-point layout method described in Example 1, three points were constructed at the well site where the gas well to be monitored is located. Following the propagation velocity measurement method described in Example 1, an open area with surface conditions consistent with the area around the gas wellhead was selected around the well site. Two microseismic sensors were buried 30cm below the surface, with a straight-line distance of 40m between them. Then, at point 1, a red brick was released from a height of 50cm above the ground, ensuring that the maximum surface area of ​​the brick was in vertical contact with the ground. The time difference between the two sensors detecting the microseismic signal was recorded. The propagation velocity of the microseismic signal was calculated as the ratio of the difference in distance between the two sensors from the brick to the time difference in signal reception. Subsequently, the propagation velocity of the microseismic signal was measured at points 2 to 6, and the measurement results are shown in Table 17. The average value of the six test results can be taken as the propagation velocity under the given surface conditions.

[0140] Table 17 Propagation speed measurement results of Example 7

[0141]

[0142] Next, following the optimal monitoring distance calculation method described in Example 1, a microseismic sensor was buried 30cm below the ground surface. Microseismic signals were collected by digging at distances of 5m, 10m, 15m, 20m, 25m, 30m, 35m, 40m, 50m, 55m, 60m, 65m, 70m, 75m, and 80m from the sensor. After testing, the optimal drilling and interception monitoring distance for this type of ground surface condition was determined to be 60m.

[0143] Furthermore, according to Figure 7 The point distribution shown involves shallowly burying three microseismic sensors around the wellhead of the gas well to be monitored, forming an equilateral triangle with the three sensors as vertices. The distance between the microseismic sensors and the wellhead is 30m, thus forming three triangular monitoring barriers around the well to be monitored. The mapping relationship between the point combination and the area where the anomaly occurred is obtained as shown in Table 18.

[0144] Table 18 Mapping Relationship between Seven Point Combinations in Example 7 and the Area Where Anomalies Occur

[0145]

[0146] Finally, according to the precise location conditions and methods for the abnormal position described in Example 1, when the abnormal position is 50m away from the wellhead and the personnel are in area B or C, a rough location of the current abnormal position can be achieved, but a precise location cannot be achieved.

[0147] Example 8

[0148] On the other hand, based on the external anomaly monitoring system for high-sulfur gas wells described in Embodiment 1 above, this embodiment of the invention also proposes an external anomaly monitoring method for high-sulfur gas wells. This method utilizes the aforementioned external anomaly monitoring system for high-sulfur gas wells to effectively monitor external anomalies in high-sulfur gas wells. Figure 8 This diagram illustrates the steps of an external anomaly monitoring method for high-sulfur gas wells according to an embodiment of this application. Figure 8 As shown, the external anomaly monitoring method for high-sulfur gas wells according to the present invention includes the following steps: Step S810: Multiple points are constructed at the well site where the gas well to be monitored is located using a signal receiving device 11, so that each point can receive a first microseismic signal in real time, wherein the first microseismic signal of each point is obtained after the second microseismic signal emitted by the target source propagates in the well site; Step S820: The anomaly type identification device 12 extracts the signal characteristic parameters of the continuous microseismic signal of each point in Step S810 under a specified time period, thereby determining the anomaly type; Step S830: The anomaly area identification device 13 determines one or more effective points that actually receive the second microseismic signal and their location distribution based on the first microseismic signals of the multiple points in Step S810, thereby determining the current anomaly area.

[0149] This invention proposes an external anomaly monitoring system and method for high-sulfur gas wells. The system's signal receiving device constructs multiple points at the well site where the gas well is to be monitored, and collects microseismic signals related to anomaly activities (e.g., intrusion by outsiders) at each point. Anomaly type identification device determines the anomaly type based on the characteristic parameters of the microseismic signals. Anomaly area identification device determines the current anomaly area based on the effective points and their location distribution of the actual collected microseismic signals. This invention proposes a reasonable and effective method for monitoring, early warning, and locating external anomalies in high-sulfur gas wells based on microseismic signals, effectively expanding the monitoring range for external anomalies in high-sulfur gas wells and enabling the identification of anomaly types and the location of anomalies. Furthermore, the external anomaly monitoring system proposed in this invention can also be widely applied in the safety monitoring of other key equipment and facilities such as oil and gas wells and oil and gas storage tanks, possessing high economic value.

[0150] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

[0151] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0152] The phrase "an embodiment" or "an embodiment" used in this specification means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" or "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0153] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. An external anomaly monitoring system for high-sulfur gas wells, characterized in that, include: The signal receiving device constructs multiple points at the well site where the gas well to be monitored is located. Each point is used to receive the first microseismic signal in real time. The first microseismic signal at each point is obtained after the second microseismic signal emitted by the target source propagates in the well site. An anomaly type identification device is used to extract signal characteristic parameters of continuous microseismic signals at each location within a specified time period to determine the anomaly type. The anomaly type includes: punch-hole theft and non-punch-hole theft. The anomaly type identification device includes: a signal analysis unit, used to extract the reception time and amplitude information of the continuous microseismic signals at each location as the signal characteristic parameters to obtain the amplitude change characteristics and signal reception time interval of each continuous microseismic signal; and an anomaly type generation unit, used to determine the current anomaly type based on the amplitude change characteristics and the signal reception time interval. If the amplitude gradually increases, the current anomaly type is determined to be non-punch-hole theft; or if the amplitude remains unchanged and the signal reception time interval is the same, the current anomaly type is determined to be punch-hole theft. An anomaly area identification device is used to determine one or more valid points that actually receive the second microseismic signal and their location distribution based on the first microseismic signal from the plurality of points, thereby determining the current anomaly area. The anomaly area identification device includes: an anomaly area division unit, used to plan multiple sets of point combinations with different numbers and locations capable of receiving the second microseismic signal, and to match an anomaly occurrence area for each set of point combinations; and an anomaly area generation unit, used to identify the points that have received the second microseismic signal in real time based on the first microseismic signal from each point. The effective number and location of two microseismic signals are determined, and the corresponding point combination is selected. The anomaly occurrence area matching the current point combination is selected as the current anomaly area. The multiple points are at least three points. If the well site where the gas well to be monitored is located is a rectangular well site, a four-point point arrangement method is adopted; or if the well site where the gas well to be monitored is located is a triangular well site, a three-point point arrangement method is adopted. The optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance are denoted as a and b, respectively, so as to form a monitoring barrier of 0~0.5a, 0.5a~a, a~1.5a and 1.5a~0.5a+b around the well to be monitored, so as to divide the anomaly area matching the four-point point arrangement method. Anomaly tracking device is used to collect identified abnormal areas in real time and determine the movement path of the abnormal area according to the time when the abnormal area was generated, thereby tracking the abnormal situation.

2. The external anomaly monitoring system according to claim 1, characterized in that, The multiple monitoring points are evenly distributed on a circle centered on the center of the gas well to be monitored, and the position of each point is determined according to the optimal monitoring distance of each point.

3. The external anomaly monitoring system according to claim 2, characterized in that, The optimal monitoring distance includes: the optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance, wherein, The optimal non-drilling theft monitoring distance / the optimal drilling theft monitoring distance is obtained by using micro-seismic sensors placed at any point in the well site to conduct walking tests / digging tests.

4. The external anomaly monitoring system according to any one of claims 1 to 3, characterized in that, The signal receiving device includes: Multiple microseismic sensors are respectively installed at different locations. These microseismic sensors are three-component microseismic sensors that meet specific technical parameter conditions, including: The bandwidth is 1~240Hz; GNSS timing accuracy is + / -10μs; Gain accuracy is 0.1%; and The sampling interval is less than or equal to 4ms.

5. The external anomaly monitoring system according to claim 4, characterized in that, The abnormal area identification device is further used to calculate the coordinates of the current abnormal area when the number of points that actually receive the second microseismic signal is greater than or equal to 3, taking the center of the gas well to be monitored as the origin of the coordinates, using the distance between each effective point and the abnormal area, and the time difference between any two effective points receiving the microseismic signal, combined with the propagation distance of the second microseismic signal in the well site where the current gas well to be monitored is located, thereby accurately locating the current abnormal area.

6. The external anomaly monitoring system according to claim 5, characterized in that, The abnormal area identification device includes: The propagation velocity calculation unit is used to deploy microseismic sensors at any two points in the well site to receive the first microseismic signal from the experimental target source, and to calculate the propagation velocity of the microseismic signal in the well site where the current gas well is located by using the signal reception time difference between each microseismic sensor and the distance between the experimental target source and each microseismic sensor, so as to obtain the propagation distance of the second microseismic signal in the well site where the current gas well is located.

7. The external anomaly monitoring system according to claim 6, characterized in that, The propagation speed calculation unit is also used to calculate the distance difference between the experimental target source and the microseismic sensors at any two points, and to use the ratio between the distance difference and the signal reception time difference as the propagation speed.

8. A method for monitoring external anomalies in high-sulfur gas wells, characterized in that, The external anomaly monitoring method is implemented using the external anomaly monitoring system as described in any one of claims 1 to 7, and the external anomaly monitoring method includes: Multiple points are constructed at the well site where the gas well to be monitored is located using a signal receiving device, so that each point can receive the first microseismic signal in real time. The first microseismic signal at each point is obtained after the second microseismic signal emitted by the target source propagates in the well site. An anomaly type identification device extracts signal characteristic parameters of continuous microseismic signals at each location within a specified time period to determine the anomaly type. The anomaly types include: punching theft and non-punching theft. Specifically, a signal analysis unit extracts the reception time and amplitude information from the continuous microseismic signals at each location as the signal characteristic parameters to obtain the amplitude variation characteristics and signal reception time interval of each continuous microseismic signal. An anomaly type generation unit determines the current anomaly type based on the amplitude variation characteristics and the signal reception time interval. If the amplitude gradually increases, the current anomaly type is determined to be non-punching theft; or if the amplitude remains constant and the signal reception time interval is the same, the current anomaly type is determined to be punching theft. The anomaly area identification device determines one or more effective points that actually receive the second microseismic signal and their location distribution based on the first microseismic signal from the multiple points, thereby determining the current anomaly area. Specifically, an anomaly area division unit plans multiple combinations of points with different numbers and locations capable of receiving the second microseismic signal, and matches an anomaly occurrence area for each combination. An anomaly area generation unit identifies the number and location of effective points that receive the second microseismic signal in real time based on the first microseismic signal from each point, determines the corresponding combination of points, and retrieves the anomaly occurrence area matching the current combination as the current anomaly area. The multiple points are at least three points. If the well site of the gas well to be monitored is a rectangular well site, a four-point point arrangement method is used; or if the well site of the gas well to be monitored is a triangular well site, a three-point point arrangement method is used. The optimal non-drilling theft monitoring distance and the optimal drilling theft monitoring distance are denoted as a and b, respectively, thereby forming a monitoring barrier 0-0 around the well of the gas well to be monitored. 0.5a, 0.5a~a, a~1.5a and 1.5a~0.5a+b, to delineate the change zone that matches the four-point layout method; Anomaly tracking device is used to collect identified abnormal areas in real time and determine the movement path of the abnormal area according to the time when the abnormal area was generated, thereby tracking the abnormal situation.

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