A crude oil leakage detection and treatment method, system, device and medium

Abstract

The application discloses a crude oil leakage detection and treatment method, system, device and medium, and relates to the technical field of crude oil leakage detection.

Description

Technical Field

[0001] This invention relates to the field of oil spill detection technology, and in particular to a method, system, equipment and medium for detecting and handling crude oil spills. Background Technology

[0002] With the continuous development of the petroleum industry, the scope of extraction and the scale of transportation are constantly expanding, and oil spill incidents are becoming more frequent. Oil spills caused by damage or rupture of subsea crude oil pipelines not only cause increasing economic losses to the country, but also cause serious pollution to the marine environment.

[0003] However, because subsea oil pipelines are located in the ocean, the transportation environment is harsh, and the marine environment is complex, changeable, and difficult to predict. Current methods for detecting leaks in subsea oil pipelines are time-consuming, inefficient, and difficult to address promptly after a leak is detected, leading to serious marine pollution. Summary of the Invention

[0004] In view of this, the purpose of this invention is to provide a method, system, device and medium for detecting and handling crude oil leaks, which can quickly detect the location of crude oil leaks and handle them in a timely manner to reduce marine pollution.

[0005] In a first aspect, embodiments of the present invention provide a method for detecting and handling crude oil leaks, comprising the following steps:

[0006] Acquire crude oil leak information, which characterizes the leak information of an underwater crude oil pipeline and indicates the target leak location and leak volume of the underwater crude oil pipeline;

[0007] The marine information is acquired, which represents ocean current information, seawater depth information, seawater density information and sediment depth information from the subsea crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the subsea crude oil pipeline.

[0008] The crude oil spill area is determined based on the crude oil spill information and the marine information, wherein the crude oil spill area represents the area where the crude oil reaches the sea level after the spill.

[0009] An oil boom is set up according to the crude oil spill area so that the oil boom surrounds the crude oil spill area.

[0010] In some optional embodiments, multiple vibration sensors are evenly distributed on the subsea crude oil pipeline, and the acquisition of crude oil leak information includes:

[0011] When the first sensor receives a first abrupt vibration signal, the second abrupt vibration signal of the second sensor is acquired. The first sensor represents the vibration sensor closest to the target leak location, the second sensor is adjacent to the first sensor, and the target leak location is located between the first sensor and the second sensor.

[0012] The first leak location is determined based on the first abrupt vibration signal, the second abrupt vibration signal, and the position information of the first and second sensors;

[0013] Acquire sonar information at the first leak location, the sonar information being obtained through a sonar device between the first sensor and the second sensor;

[0014] The location of the target leak is obtained based on the sonar information;

[0015] The leakage amount is determined based on the sonar information and pipeline parameter information, wherein the pipeline parameter information characterizes the pipeline diameter, pipeline roughness, pressure difference between the inside and outside of the pipeline, crude oil viscosity, and crude oil density of the subsea crude oil pipeline.

[0016] In some optional embodiments, determining the first leak location based on the first abrupt vibration signal, the second abrupt vibration signal, and the position information of the first and second sensors includes:

[0017] A first distance is determined based on the first position of the first sensor and the second position of the second sensor, wherein the first distance represents the distance between the first sensor and the second sensor on the underwater crude oil pipeline;

[0018] The distance difference is determined based on the time difference and transmission speed of the first and second abrupt vibration signals, and the distance difference represents the difference between the second distance from the target leak location to the first sensor and the third distance from the target leak location to the second sensor;

[0019] The first leak location is determined based on the distance difference and the first distance.

[0020] In some optional embodiments, obtaining the target leak location based on the sonar information includes:

[0021] A sonar map is obtained by labeling the sonar information.

[0022] The underwater crude oil pipeline model was obtained based on the sonar map annotations.

[0023] Identify defective areas on the underwater crude oil pipeline model and configure the defective areas as the target leak locations.

[0024] In some optional embodiments, determining the leakage amount based on the sonar information and pipeline parameter information includes:

[0025] After the defect area is marked based on the sonar information, the shape of the pipe crack in the defect area is extracted.

[0026] The crude oil transport speed in the defect area is determined based on the pipe diameter, the pipe roughness, the crude oil viscosity, and the crude oil density.

[0027] The leakage amount is determined based on the transport speed, the crack shape, the pressure difference between the inside and outside of the pipeline, the crude oil viscosity, and the crude oil density.

[0028] In some optional embodiments, determining the oil spill area based on the oil spill information and the marine information includes:

[0029] The flow path and velocity of the crude oil after the leak are determined based on the target leak location, ocean current information, seawater depth information, seawater density information, sediment depth information, and crude oil information, wherein the crude oil information includes crude oil viscosity, crude oil density, and crude oil water content.

[0030] The point of crude oil leakage at sea level was determined based on the described flow path;

[0031] The leakage time of crude oil at sea level is determined based on the flow velocity, wherein the leakage time characterizes the time it takes for crude oil to travel from the target leakage location to the leakage point;

[0032] The crude oil leak area surrounding the leak point is determined based on the leak volume and the leak time.

[0033] In some optional embodiments, after determining the oil spill area based on the oil spill information and the marine information, the method further includes:

[0034] The ocean current scouring coefficient at the target leak location is determined based on the ocean current information.

[0035] The crack shape variation diagram is determined based on the crack shape, the pressure difference between the inside and outside of the pipeline, the ocean current scouring coefficient, and the pipeline material.

[0036] The leakage rate variation diagram at the target leakage location is determined based on the crack variation diagram.

[0037] The corrected leakage area is obtained by correcting the crude oil leakage area in real time based on the leakage change diagram.

[0038] The oil boom is set up according to the modified leak area so that the oil boom surrounds the crude oil at sea level, and the amount of crude oil in the oil boom is within a preset oil containment amount.

[0039] In some optional embodiments, determining the flow path and velocity of the crude oil spill based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, and the sediment depth information includes:

[0040] The initial path and initial velocity are determined based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, and the sediment depth information.

[0041] The first dielectric constant of crude oil, the second dielectric constant of pure oil, and the third dielectric constant of seawater were obtained.

[0042] The water content of the crude oil is determined based on the first dielectric constant, the second dielectric constant, and the third dielectric constant;

[0043] The flow path and flow velocity are obtained by correcting the initial path and initial velocity based on the crude oil water content, crude oil viscosity, and crude oil density.

[0044] In a second aspect, embodiments of the present invention provide a computer device, the computer device including a processor, a memory, and a computer program stored in the memory and executable by the processor, wherein when the computer program is executed by the processor, it implements the steps of the above-described method.

[0045] Thirdly, embodiments of the present invention provide a computer-readable storage medium storing a processor-executable program, which, when executed by a processor, is used to perform the method described above.

[0046] Implementing the embodiments of the present invention has the following beneficial effects: The embodiments of the present invention provide a method for detecting and handling crude oil leaks, comprising: acquiring crude oil leak information, wherein the crude oil leak information characterizes the leak information of an underwater crude oil pipeline, and the leak information indicates the target leak location and leak volume of the underwater crude oil pipeline; acquiring marine information, wherein the marine information characterizes ocean current information, seawater depth information, seawater density information, and sediment depth information from the underwater crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the underwater crude oil pipeline; determining the crude oil leak area based on the crude oil leak information and the marine information, wherein the crude oil leak area characterizes the area where the crude oil reaches the sea surface after the leak; and setting up oil booms according to the crude oil leak area to surround the crude oil leak area. By detecting the location and volume of the crude oil leak and determining the crude oil leak area at the sea surface based on specific marine information, corresponding oil booms can be set up in advance according to the crude oil leak area to contain the leaked crude oil, prevent the crude oil from spreading, and thus reduce marine pollution. Attached Figure Description

[0047] Figure 1 This is a schematic diagram of the structure of a crude oil transportation system provided in an embodiment of the present invention;

[0048] Figure 2 This is a flowchart illustrating the steps of a crude oil leak detection and handling method provided in an embodiment of the present invention;

[0049] Figure 3 This is a schematic diagram of the installation of the vibration sensor provided in an embodiment of the present invention;

[0050] Figure 4 This is a schematic diagram of a crude oil leak surrounding a crude oil transportation system provided in an embodiment of the present invention;

[0051] Figure 5 This is a flowchart illustrating the steps of a vibration sensor detecting a target leak location according to an embodiment of the present invention.

[0052] Figure 6 This is a flowchart of the steps for modifying the oil boom based on changes in crack shape provided in an embodiment of the present invention;

[0053] Figure 7 This is a schematic diagram of the mounting bracket for the monitoring equipment provided in an embodiment of the present invention;

[0054] Figure 8 This is a schematic diagram of the structure of a computer device provided in an embodiment of the present invention.

[0055] Attached diagrams: Tanker 100, Float 200, Suction pipe 210, Repeater 220, Control module 230, Transport pipe 300, Sediment 310, Flow path 320, Ground 400, Communication base station 410, Monitoring equipment 500, Oil boom 600, Crude oil spill area 700. Detailed Implementation

[0056] Embodiments of the present invention are described in detail below. Examples of these embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar elements or elements having the same or similar functions throughout. The embodiments described below with reference to the accompanying drawings are exemplary and are only used to explain the present invention, and should not be construed as limiting the present invention.

[0057] In the description of this invention, it should be understood that the orientation descriptions, such as up, down, front, back, left, right, etc., are based on the orientation or positional relationship shown in the accompanying drawings. They are only for the convenience of describing this 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. Therefore, they should not be construed as limiting this invention.

[0058] In the description of this invention, "several" means one or more, "more than" means two or more, "greater than," "less than," and "exceeding" are understood to exclude the stated number, while "above," "below," and "within" are understood to include the stated number. The use of "first" and "second" in the description is merely for distinguishing technical features and should not be construed as indicating or implying relative importance, or implicitly indicating the number of indicated technical features, or implicitly indicating the order of the indicated technical features.

[0059] In the description of this invention, unless otherwise explicitly defined, terms such as "set up," "install," and "connect" should be interpreted broadly, and those skilled in the art can reasonably determine the specific meaning of the above terms in this invention in conjunction with the specific content of the technical solution.

[0060] The embodiments of the present invention will be further described below with reference to the accompanying drawings.

[0061] Reference Figure 1An embodiment of the present invention provides a crude oil transportation system, which includes an oil tanker 100, a buoy 200, a transportation pipeline 300, and a land surface 400. The land surface 400 is equipped with a communication base station 410 that communicates with a control module 230 on the buoy 200. The oil tanker 100 transports crude oil from its tanker to a repeater 220 via an oil suction pipe 210 for water content measurement, density measurement, and viscosity testing. The crude oil is then transported from the seabed to the land surface 400 via the transportation pipeline 300. The underwater crude oil pipeline is covered by sediment 310, and in the event of a crude oil leak, a corresponding crude oil leak area 700 is formed at the sea level. The area of ​​the crude oil leak area 700 is S, and the oil flows from the leak location to the sea level via a corresponding flow path 320.

[0062] like Figure 2 As shown, in a first aspect, embodiments of the present invention provide a method for detecting and handling crude oil leaks, applied to the above-mentioned... Figure 1 The crude oil transportation system includes the following steps.

[0063] S100. Obtain crude oil leakage information, wherein the crude oil leakage information characterizes the leakage information of the subsea crude oil pipeline, and the leakage information indicates the target leakage location and leakage amount of the subsea crude oil pipeline.

[0064] Specifically, leakage information from the underwater crude oil pipeline described in this application can be obtained through multiple methods. Firstly, various sensors installed on the pipeline, such as pressure sensors and flow sensors, can monitor changes in parameters like pressure and flow rate of the crude oil within the pipeline in real time. When a leak occurs, these parameters will exhibit abnormal fluctuations. By analyzing this abnormal data, the system can preliminarily determine the occurrence of a leak and further pinpoint the location of the leak. For example, if a pressure sensor detects a sudden drop in pressure within a certain section of the pipeline, combined with changes in flow sensor data, it can be determined that a leak may exist in that section of the pipeline.

[0065] On the other hand, refer to Figure 3 Multiple vibration sensors can also be used for location detection. When a sudden change occurs in the vibration signal received by one vibration sensor, a corresponding pipeline rupture has occurred on the surface, causing vibration. The location of the leak can then be determined by the vibration signal from another vibration sensor. The leak can also be determined by detecting changes in the pipeline flow rate at the inlet and outlet of the underwater crude oil pipeline, or by calculating based on the shape of the specific leak location and pipeline parameters; the specific method of obtaining this information is not limited.

[0066] Leakage volume determination: Leakage volume can be calculated using methods such as fluid dynamics formulas, empirical formulas, or numerical simulations. In practice, historical data and statistical analysis can be combined to correct and verify the calculation results, thereby improving the accuracy of leakage volume calculation. For example, the currently calculated leakage volume can be adjusted by referring to empirical data from similar past leakage accidents.

[0067] S200. Obtain marine information, wherein the marine information represents ocean current information, seawater depth information, seawater density information and sediment depth information from the subsea crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the subsea crude oil pipeline.

[0068] Specifically, after determining the target leak location, ocean current information is acquired in the corresponding marine area.

[0069] Ocean current information: Obtaining ocean current information from underwater oil pipelines to sea level can be used to predict the diffusion path after an oil spill. Ocean current data near the target leak location can be obtained through methods such as ocean monitoring buoys and satellite remote sensing. Ocean monitoring buoys can measure the speed and direction of ocean currents in real time, while satellite remote sensing can provide information on the distribution of ocean currents over large areas. For example, satellite images can show the direction and velocity of ocean currents in different regions; combined with real-time data from ocean monitoring buoys, a more accurate understanding of the ocean current conditions around the target leak location in the underwater oil pipeline can be achieved.

[0070] Seawater depth information: Seawater depth information can be measured using equipment such as echo sounders and multibeam echo sounders. Echo sounders emit sound waves into the seabed and receive the reflected signals, calculating the seawater depth based on the signal propagation time. Multibeam echo sounders can simultaneously measure the echo signals of multiple beams, thus obtaining more detailed seabed topography and seawater depth information.

[0071] Seawater density information: Seawater density is affected by factors such as temperature and salinity. Seawater density can be calculated by sampling and analyzing parameters such as temperature and salinity, and then using relevant formulas. Alternatively, historical data from marine databases can be used to obtain seawater density information for that area. Changes in seawater density affect the buoyancy and diffusion behavior of crude oil in seawater; therefore, the seawater density at a depth of 700 meters in the oil spill area can be used to calculate the flow path 320 and flow velocity of the spilled crude oil.

[0072] Sediment Depth Information: Sediment depth information indicates the depth of sediment buried in underwater oil pipelines and can be used to calculate the time it takes for oil to permeate the sediment (310). Sediment depth information can be obtained using sonar equipment carried by underwater robots or ground-penetrating radar (GPR). GPR detects the distribution and thickness of seabed sediment (310) by emitting electromagnetic waves and receiving the reflected signals. Sonar equipment detects the specific sediment depth by sending sonar signals and analyzing the reflected signals.

[0073] S300. Based on the crude oil leak information and the marine information, determine the crude oil leak area 700, whereby the crude oil leak area 700 represents the area where the crude oil reaches the sea level after the leak.

[0074] Specifically, combining information on the crude oil spill (target location and volume) and ocean information (ocean currents, seawater depth, density, etc.), a pre-defined diffusion model is used to predict the area of ​​the oil spill reaching sea level. Commonly used diffusion models include Gaussian diffusion models and Lagrange diffusion models, among others. The Gaussian diffusion model assumes that the pollutant (crude oil) follows a Gaussian distribution during diffusion, calculating the concentration distribution of pollutants at different locations by considering factors such as the location of the leak source, the volume of the spill, wind speed, and wind direction (which can be analogous to ocean current speed and direction in the ocean). The Lagrange diffusion model, on the other hand, tracks the trajectory of each oil droplet, considering the buoyancy and drag of the droplets in seawater, as well as the effects of ocean currents, to simulate the diffusion process of the oil droplets.

[0075] Comprehensive Analysis: When determining the crude oil spill area 700, other factors also need to be considered, such as the mixing effect of seawater and the emulsification of oil droplets. Seawater mixing allows the crude oil to spread more evenly within the seawater, while the emulsification of oil droplets alters their physical properties and affects their diffusion behavior. By incorporating these factors into a comprehensive analysis and calculation of the diffusion process, the extent and shape of the crude oil spill area 700 can be determined more accurately.

[0076] S400. An oil boom 600 is set up according to the crude oil spill area 700 so that the oil boom 600 surrounds the crude oil spill area 700.

[0077] Specifically, refer to Figure 4 Based on the size and shape of the oil spill area 700 and the marine environmental conditions (such as wind speed and waves), a suitable type of oil boom 600 is selected, including floating oil booms 600 and inflatable oil booms 600. Floating oil booms 600 are suitable for calm sea surfaces and can effectively prevent the spread of oil. Inflatable oil booms 600 have better flexibility and adaptability and can be used in complex sea conditions.

[0078] When deploying the oil boom 600, it is essential to ensure that it completely surrounds the oil spill area 700. The boom 600 can be transported to the designated location using vessels or other equipment (such as drones) and installed according to the design plan. During installation, care must be taken to ensure the connection and securement of the boom 600 to prevent it from loosening or detaching due to waves and ocean currents. Furthermore, the position and shape of the boom 600 should be adjusted promptly based on the oil spill situation and changes in the marine environment to improve the effectiveness of the oil containment.

[0079] In some alternative embodiments, refer to Figure 5 Multiple vibration sensors are evenly installed on the underwater crude oil pipeline. The acquisition of crude oil leak information includes:

[0080] S110. When the first sensor receives the first sudden vibration signal, the second sudden vibration signal of the second sensor is acquired. The first sensor represents the vibration sensor closest to the target leakage location. The second sensor is adjacent to the first sensor, and the target leakage location is located between the first sensor and the second sensor.

[0081] S120. Determine the first leak location based on the first sudden vibration signal, the second sudden vibration signal, and the position information of the first sensor and the second sensor;

[0082] S130. Obtain sonar information of the first leak location, wherein the sonar information is obtained through a sonar device between the first sensor and the second sensor;

[0083] S140. Obtain the target leakage location based on the sonar information;

[0084] S150. Determine the leakage amount based on the sonar information and pipeline parameter information, wherein the pipeline parameter information characterizes the pipeline diameter, pipeline roughness, pressure difference between inside and outside the pipeline, oil flow rate, crude oil viscosity, and crude oil density of the subsea crude oil pipeline.

[0085] Specifically, multiple vibration sensors are evenly distributed along the underwater crude oil pipeline to monitor its operating status in real time. When a leak occurs, crude oil is ejected from the pipeline at high speed, causing vibrations that are detected by nearby sensors.

[0086] The first sensor, closest to the leak location, receives the first abrupt vibration signal, indicating an oil leak in its vicinity. Since the first sensor is the closest to the target leak location, it then acquires the second abrupt vibration signal received by the adjacent second sensor, with the target leak location located between these two sensors. The abrupt vibration signal typically manifests as a significant change in parameters such as vibration amplitude and frequency recorded by the sensors within a short period, clearly distinguishing it from signals under normal operating conditions.

[0087] Vibrations generated by crude oil leaks propagate at a certain speed in the pipeline and its surrounding medium. The arrival time and intensity of the first and second abrupt vibration signals are related to the leak location and the relative position of the sensors. Combining the positional information of the first and second sensors (their installation coordinates on the pipeline are known), the location of the first leak is estimated using the propagation law of vibration signals and related algorithms. For example, the approximate location of the leak point can be solved by establishing an equation based on the arrival time difference of the vibration signals through geometric relationships. Assuming the propagation speed of vibration in the medium is v, the time when the first sensor receives the signal is t1, the time when the second sensor receives the signal is t2, the first distance between the two sensors is L, the second distance from the leak point to the first sensor is L1, and the third distance from the leak point to the second sensor is L2, then the time difference between the signals received by the second and first sensors is t2-t1 = Δt, and the distance difference between the second and third distances is ΔL = L2-L1. Therefore, v(t2-t1) = L2-L1, L = L1+L2, thus deriving:

[0088]

[0089] Therefore, the first leak location can be obtained based on the preset first position of the first sensor and the second position of the second sensor.

[0090] Obtaining sonar information at the first leak location: A sonar device is installed between the first and second sensors, or the sonar device is moved to the first leak location using an underwater robot. Sonar utilizes the propagation characteristics of sound waves in water, emitting ultrasonic waves and receiving reflected waves to detect the position, shape, and other information of target objects. Once the first leak location is initially determined, the sonar device is activated to probe the area. The ultrasonic waves emitted by the sonar device are reflected when they encounter leaking crude oil, pipe walls, etc., and the reflected waves are received and recorded by the sonar receiver. These reflected waves contain detailed information about the leak location and situation, such as establishing a corresponding sonar intensity map based on the intensity and propagation time of the reflected waves.

[0091] The location of the leak can be determined using sonar information: The reflected wave data received by the sonar is processed and analyzed. By analyzing the propagation time of the reflected waves, the distance between the sonar equipment and the leak point can be calculated; based on the intensity and direction of the reflected waves, the specific location of the leak point can be determined. Combining the installation location of the sonar equipment with known pipeline geometry, methods such as triangulation can be used to more accurately determine the location of the leak. For example, if the intensity and time of the reflected waves received from the ultrasonic waves emitted by the sonar equipment differ in different directions, the accurate coordinates of the leak point in three-dimensional space can be obtained by establishing a mathematical model and solving it.

[0092] The leakage rate is determined based on sonar information and pipeline parameters: Sonar information provides characteristics of the leak, such as its size and shape. By analyzing the characteristics and patterns of the sonar reflected waves, parameters such as the leak area can be estimated. Combined with pipeline parameters, such as the pipeline diameter determining the cross-sectional area for crude oil flow, pipeline roughness affecting flow resistance, the pressure difference between the inside and outside of the pipeline driving the leakage, the oil flow rate reflecting the normal crude oil transport volume, and crude oil viscosity and density affecting flow characteristics, the leakage rate is calculated using fluid mechanics principles and related formulas, such as Bernoulli's equation and the continuity equation. For example, according to Bernoulli's equation:

[0093]

[0094] Where F1 is the pressure inside the pipeline, F2 is the pressure outside the pipeline, ρ is the density of crude oil, V1 is the crude oil flow velocity inside the pipeline, V2 is the crude oil flow velocity outside the pipeline, h1 is the height inside the pipeline, h2 is the height outside the pipeline, and g represents the acceleration due to gravity. Combining the leak area and parameters such as pressure and flow velocity inside the pipeline, the leaking crude oil flow velocity V2 can be calculated. Multiplying this by the leak area gives the leakage amount. In actual calculations, appropriate correction factors need to be considered to more accurately reflect the actual situation.

[0095] In some optional embodiments, determining the first leak location based on the first abrupt vibration signal, the second abrupt vibration signal, and the position information of the first sensor and the second sensor includes: determining a first distance based on a first position of the first sensor and a second position of the second sensor, wherein the first distance characterizes the distance between the first sensor and the second sensor on the subsea crude oil pipeline; determining a distance difference based on the time difference and transmission speed of the first abrupt vibration signal and the second abrupt vibration signal, wherein the distance difference characterizes the difference between a second distance from the target leak location to the first sensor and a third distance from the target leak location to the second sensor; and determining the first leak location based on the distance difference and the first distance.

[0096] Specifically, refer to Figure 4 Vibration sensors, evenly distributed along the subsea crude oil pipeline, each have a fixed installation position. The first position (P2) of the first sensor and the second position (P3) of the second sensor can be determined using a pre-defined coordinate system. For example, a one-dimensional coordinate system can be established along the pipeline's extension direction, with the pipeline's starting end as the origin, and each sensor's position corresponding to a specific coordinate value. Alternatively, the precise position of the sensor can be determined in three-dimensional space, taking into account factors such as the pipeline's laying depth and horizontal orientation. Based on the first position of the first sensor and the second position of the second sensor, the first distance is determined using the corresponding distance calculation formula, as detailed above. The first distance is the actual distance between the first and second sensors on the subsea crude oil pipeline.

[0097] When an underwater crude oil pipeline leaks, the resulting vibrations propagate outwards at a certain speed. The first and second sensors will receive the sudden vibration signals sequentially. Through the sensor data acquisition and processing system, the reception time t1 of the first sudden vibration signal and the reception time t2 of the second sudden vibration signal can be accurately recorded, and then their time difference Δt = t2 - t1 can be calculated.

[0098] The propagation velocity *v* of the vibration wave in an underwater crude oil pipeline is a known parameter, which can be obtained through experimental measurement, theoretical calculation, or reference to relevant materials; the specific method of obtaining this parameter is not limited here. Different media (such as pipeline materials, surrounding seawater, etc.) and conditions (such as temperature, pressure, etc.) will affect the propagation velocity of the vibration wave, therefore, the corresponding velocity value needs to be determined according to the actual situation. Based on the time difference Δt and the propagation velocity *v*, the specific second and third distances can be calculated using the distance calculation formula mentioned above, thereby obtaining the first leak location (P1). The specific calculation is as described above and will not be repeated here.

[0099] In some optional embodiments, obtaining the target leak location based on the sonar information includes: obtaining a sonar map based on the sonar information; obtaining a subsea crude oil pipeline model based on the sonar map; identifying defective areas on the subsea crude oil pipeline model; and configuring the defective areas as the target leak location.

[0100] Specifically, sonar equipment emits ultrasonic signals underwater. When these ultrasonic signals encounter objects (such as subsea oil pipelines, surrounding seawater, sediment, etc.), they produce reflected waves of varying intensities, which are then captured by the sonar receiver. The material, shape, and location of different objects will cause variations in the intensity, propagation time, and frequency of the reflected waves.

[0101] Sonar equipment converts the received reflected wave signals into electrical signals, which are then analyzed and processed by a signal processing system. The processing includes operations such as filtering, amplification, and spectral analysis to remove noise interference, enhance useful signals, and extract key characteristic information of the reflected waves.

[0102] Based on the processed reflected wave characteristics, sonar maps are generated by marking them on a specific display interface (such as a monitoring terminal on the ground-based 400-meter tower) or software. Different colors, brightness levels, or patterns on the sonar map can represent information such as the intensity and distance of the reflected waves. For example, stronger reflected waves are represented by brighter colors, while weaker reflected waves are represented by darker colors (or stronger reflected waves are represented by denser dots, while weaker reflected waves are represented by sparser dots); objects closer to the sonar equipment are positioned closer to the center of the map, while more distant objects are located at the edges. In this way, the sonar map can visually represent the distribution of objects in the underwater environment.

[0103] A model of the underwater crude oil pipeline was obtained based on sonar imagery annotations. The sonar images provided basic information about the underwater environment. Based on this, and combined with known parameters of the underwater crude oil pipeline (such as its route and diameter), a model was constructed using specialized modeling software or platforms. During model construction, the characteristic information related to the underwater crude oil pipeline on the sonar images was carefully analyzed. For example, based on the shape, position, and continuity of the pipeline's reflected waves shown in the images, the specific direction and location of the pipeline in the model were determined. The information from the sonar images was accurately mapped into the model, enabling the model to realistically reflect the actual situation of the underwater crude oil pipeline.

[0104] The constructed underwater crude oil pipeline model was annotated to clarify the specific parameters and characteristics of each part of the model. The annotations included location information for different pipeline sections, connection points, valves, etc., as well as attribute information such as pipeline material and diameter variations. Simultaneously, the model was further refined based on details from sonar imaging, making it more accurate and complete.

[0105] Identifying defective areas on an underwater crude oil pipeline model and designating these areas as target leak locations: This involves analyzing the underwater crude oil pipeline model using image processing and pattern recognition techniques. By setting appropriate algorithms and parameters, the model is used to detect areas that differ from normal pipeline characteristics; these areas are potential defective regions. For example, edge detection algorithms can be used to identify discontinuous or abnormal edges in the pipeline model, or machine learning algorithms can be used to train the model to automatically identify defective areas.

[0106] Further analysis and judgment are performed on the detected undetermined defect areas to eliminate interfering areas and obtain the defect areas of the pipeline. Combining the reflected wave characteristics in the sonar spectrum and information such as pipeline operating parameters, it is determined whether a defect actually exists in this area. For example, if the reflected wave intensity at a certain location in the sonar spectrum is abnormally high or low and matches the location of the defect area detected in the model, then this area is a defect area. The defect area on the underwater crude oil pipeline model is configured as the target leak location. Through further identification and processing of sonar information, the specific pipeline area where the leak occurred is accurately determined within the first leak location.

[0107] In some optional embodiments, determining the leakage amount based on the sonar information and pipeline parameter information includes: after marking the defect area based on the sonar information, extracting the shape of the pipeline crack in the defect area; determining the crude oil transport speed in the defect area based on the pipeline diameter, the pipeline roughness, the crude oil viscosity, and the crude oil density; and determining the leakage amount based on the transport speed, the crack shape, the pressure difference between the inside and outside of the pipeline, the crude oil viscosity, and the crude oil density.

[0108] Specifically, a model of an underwater crude oil pipeline is constructed using sonar information, and defect areas on the pipeline are marked. Further processing and analysis of the sonar reflected signals, such as signal intensity distribution and reflection angle, identifies and delineates the approximate outline of pipeline cracks within the defect area. Image processing software or algorithms are used to enhance and denoise the defect area images in the sonar atlas, improving image clarity and quality. Then, edge detection and contour extraction techniques are employed to accurately extract the shape of the pipeline cracks, including feature parameters such as crack length, width, depth, and shape irregularity. Furthermore, sonar information can be used to perform 3D reconstruction of the defect area, providing a more intuitive and accurate understanding of the shape and location of pipeline cracks in 3D space.

[0109] Based on parameters such as pipe diameter, pipe roughness, crude oil viscosity, and crude oil density, a preset formula can be used to calculate the crude oil transport velocity in the defect area. The preset formula is:

[0110]

[0111] Where h f Let L be the head loss along the pipe, f be the friction coefficient of the pipe, and L be the friction coefficient of the pipe. GLet D be the pipe length, d be the pipe diameter, d be the pipe inner diameter, V1 be the crude oil flow velocity at the leak point, g be the gravitational acceleration, ε be the pipe roughness, γ be the crude oil viscosity, and ρ be the crude oil density. Given the pipe diameter D and pipe roughness ε, f can be determined. Given the crude oil viscosity γ and density δ, and combining this with the actual pipe conditions and relevant physical parameters, the crude oil transport velocity V1 in the defect area can be derived.

[0112] In practice, it is also necessary to consider underwater environmental factors, such as the impact of seawater pressure and temperature on the properties and flow of crude oil. The calculated transport speed needs to be adjusted accordingly based on the degree of influence. For example, changes in seawater temperature and pressure can alter the viscosity and density of crude oil, thus affecting the transport speed. Therefore, the initially calculated speed needs to be adjusted based on the specific environmental parameters and the relationship between the changes in the physical properties of the crude oil to obtain a more accurate transport speed value.

[0113] The leakage rate is determined based on the transport speed, crack shape, pressure difference between the inside and outside of the pipeline, crude oil viscosity, and crude oil density. Then, using Bernoulli's equation, the corresponding leakage rate is calculated. Bernoulli's equation is shown in the formula above:

[0114]

[0115] For leakage at a pipe crack, first determine the equivalent flow area A of the crack based on its shape. Given the pressure difference ΔF between the inside and outside of the pipe, the actual leakage velocity V2 at the crack can be calculated using Bernoulli's equation and the relevant pressure-velocity relationship, combined with the previously obtained transport velocity V1. The leakage amount Q = A × V2 per unit time can then be calculated.

[0116] In some optional embodiments, determining the crude oil leak area 700 based on the crude oil leak information and the ocean information includes: determining the flow path 320 and flow velocity of the crude oil after the leak based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, the sediment depth information, and the crude oil information, wherein the crude oil information includes crude oil viscosity, crude oil density, and crude oil water content; determining the leak point of the crude oil at sea level based on the flow path 320; determining the leak time of the crude oil at sea level based on the flow velocity, wherein the leak time characterizes the time it takes for the crude oil to travel from the target leak location to the leak point; and determining the crude oil leak area 700 surrounding the leak point based on the leak volume and the leak time.

[0117] Specifically, the flow path 320 and flow velocity after the crude oil leak are determined: the target leak location determines the starting point of the crude oil leak, while ocean current information (including the speed and direction of the ocean current) affects the direction and speed of crude oil flow in seawater. Seawater depth information affects the vertical flow space of crude oil and the pressure changes it experiences. Seawater density information interacts with crude oil density, determining the buoyancy of crude oil in seawater, thus affecting its rising or sinking trend. Sediment depth information can determine whether the crude oil will be blocked or buried by sediment 310. Crude oil viscosity in the crude oil information affects the internal friction of the crude oil, thus affecting its ease of flow; crude oil water content changes the physical properties of crude oil and also affects its flow characteristics.

[0118] Establishing a mathematical model: Integrating these factors, a mathematical model is established using the relevant principles of fluid mechanics and ocean dynamics. For example, numerical simulation methods, such as the finite element method or the finite volume method, can be used to discretize the underwater space. Boundary and initial conditions are set according to the aforementioned factors, and the flow path 320 and velocity distribution of crude oil in seawater are calculated by solving the fluid motion equations (such as the Navier-Stokes equations). For complex marine environments, the influence of factors such as waves and tides on crude oil flow also needs to be considered, and the model needs to be modified and improved accordingly.

[0119] Determining the crude oil leak point at sea level: Based on the flow path 320 calculated using the mathematical model above, trace the crude oil along this path, starting from the target leak location. As the crude oil flows through the seawater, determine its final position at sea level based on changes in its flow direction and path; this position is the leak point at sea level. During the tracing process, it is necessary to consider potential diffusion and mixing phenomena during the oil flow, as well as the influence of marine environmental factors on its path. For example, changes in ocean current direction or velocity can alter the flow path 320, thus affecting the location of the leak point (which can be considered the center point of the crude oil leak to sea level).

[0120] Determining the crude oil leakage time at sea level: Given the flow velocity of the crude oil in seawater (determined through mathematical model calculations) and the distance from the target leakage location to the leakage point at sea level (obtainable through calculations of flow path 320), the time it takes for the crude oil to travel from the target leakage location to the leakage point, i.e., the leakage time, is calculated based on the relationship between velocity, distance, and time. It is important to note that since the velocity of the crude oil changes during its flow, a segmented calculation method can be used. The flow path 320 is divided into several small segments, the time for each segment is calculated separately, and then the times of all segments are added together to obtain the total leakage time.

[0121] Determine the crude oil spill area 700 around the leak point: Given the leak volume (calculated previously based on relevant information) and the leak time, determine the extent of crude oil diffusion at sea level based on the size of the leak and the duration of the leak. If the leak volume is large and the leak time is long, the crude oil will diffuse over a larger area at sea level (crude oil continuously diffuses as it flows to sea level, therefore the longer the leak time, the wider the diffusion, and the larger the crude oil spill area 700 will be); conversely, if the leak volume is small or the leak time is short, the diffusion range will be relatively small.

[0122] A diffusion model can be used to further determine the shape and size of the oil spill area 700. For example, the Gaussian diffusion model assumes that the diffusion of crude oil at sea level follows a Gaussian distribution. By setting appropriate diffusion parameters, the crude oil concentration distribution at different locations can be calculated, thereby determining the boundary of the oil spill area 700. Based on the calculation results, an area is defined around the leak point where the crude oil concentration reaches a preset threshold (e.g., a concentration value that may have an impact on the marine ecological environment or human activities; the specific threshold setting is not limited). This area is the oil spill area 700.

[0123] In some alternative embodiments, refer to Figure 6 After determining the crude oil spill area 700 based on the crude oil spill information and the marine information, the method further includes:

[0124] S310. Determine the ocean current scouring coefficient at the target leakage location based on the ocean current information;

[0125] S320. Determine the crack change diagram of the crack shape based on the crack shape, the pressure difference between the inside and outside of the pipeline, the ocean current scouring coefficient, and the pipeline material;

[0126] S330. Determine the leakage change diagram of the target leakage location based on the crack change diagram;

[0127] S340. The crude oil leakage area is corrected in real time according to the leakage change diagram to obtain the corrected leakage area;

[0128] S350. The oil boom 600 is set up according to the modified leak area so that the oil boom 600 surrounds the crude oil at sea level, and the amount of crude oil in the oil boom 600 is within the preset oil containment amount.

[0129] Specifically, the ocean current scour coefficient at the target leak location is determined based on ocean current information: First, comprehensive ocean current information near the target leak location is collected, including current speed, direction, and seasonal variations. This data can be obtained through various means, such as ocean monitoring buoys, satellite remote sensing, and marine meteorological stations, without specific limitations. Then, the collected ocean current data is analyzed in depth to understand the specific characteristics of the ocean currents at the target leak location. Based on the ocean current speed and direction, combined with the geographical environment of the target leak location (such as seabed topography and pipeline orientation), the relevant principles of fluid mechanics are applied to determine the ocean current scour coefficient. Generally, the faster the ocean current, the stronger the scour effect on the pipeline, and the larger the scour coefficient; simultaneously, a larger angle between the ocean current direction and the pipeline also increases the scour force. A mathematical model can be established, substituting parameters such as ocean current speed and direction into the model to calculate the corresponding scour coefficient. For example, empirical formulas can be used to estimate the scour coefficient based on ocean current speed and relevant pipeline parameters.

[0130] Crack shape and crack variation diagram determined by crack shape, pressure difference between the inside and outside of the pipeline, ocean current erosion coefficient, and pipeline material: Crack shape is one of the important factors affecting crude oil leakage; different crack shapes lead to different leakage patterns and speeds. The pressure difference between the inside and outside of the pipeline is the driving force behind crude oil leakage; the greater the pressure difference, the faster the leakage rate. The ocean current erosion coefficient reflects the scouring effect of ocean currents on pipeline cracks and affects crack development and variation. The pipeline material determines the pipeline's strength and erosion resistance; different pipeline materials will exhibit different crack variations under the same erosion conditions.

[0131] Numerical simulation methods such as finite element analysis are used to incorporate factors such as crack shape, pressure difference between the inside and outside of the pipeline, ocean current scouring coefficient, and pipeline material into the crack calculation model. Through simulation calculations, the changes in crack shape over time under the combined effects of these factors are analyzed, thereby generating a crack shape change diagram. For example, over time, the crack will gradually expand, widen, or develop new branches.

[0132] Determine the leakage rate variation at the target leak location based on the crack change diagram: Based on the changes in crack shape in the crack change diagram, and combining with the principles of fluid mechanics, establish the relationship between leakage rate and crack shape. Generally, the larger the crack area, the greater the leakage rate; the crack shape also affects the flow resistance of crude oil, thus affecting the leakage rate. For example, for a narrow crack and a wide crack, under the same pressure difference inside and outside the pipeline, the wide crack will lead to a greater leakage rate.

[0133] Calculating and plotting leakage rate changes: Based on the established relationship between leakage rate and crack shape, and the change in crack shape over time in the crack change graph, the leakage rate at each time point is calculated. Then, with time on the x-axis and leakage rate on the y-axis, a leakage rate change graph of the target leakage location is plotted (which can be displayed on a monitoring terminal). The leakage rate change graph clearly shows the trend of leakage rate changes over time.

[0134] The corrected leak area is obtained by real-time correction of the crude oil leak area 700 based on the leak volume change map: The crude oil leak area 700 is monitored and analyzed in real time according to the leak volume change map. When the leak volume changes, it indicates that the diffusion of crude oil in seawater has also changed. For example, if the leak volume suddenly increases, it means that the crack has further expanded or a new leak point has appeared, and the crude oil will spread to a larger area in the seawater.

[0135] Correction Method: Based on changes in the leakage volume and combined with marine information (such as ocean currents and seawater depth), the crude oil leak area 700 is corrected. A diffusion model can be used to recalculate the diffusion range and shape of the crude oil in seawater based on the new leakage volume and marine environmental parameters, thus obtaining the corrected leak area. For example, if the leakage volume increases, the radius of the crude oil leak area 700 calculated by the diffusion model will increase, and the area of ​​the crude oil leak area 700 will need to be expanded accordingly.

[0136] An oil boom 600 is deployed according to the corrected leak area to surround the crude oil at sea level, ensuring the amount of crude oil within the boom remains within a preset containment limit. A suitable oil boom 600 is selected based on the corrected leak area. The selection of the oil boom 600 considers factors such as its size, material, and flexibility to ensure effective containment of the crude oil at sea level. Simultaneously, the shape and size of the oil boom 600 are adjusted appropriately according to the preset containment limit to ensure the amount of crude oil within it does not exceed the preset value. For example, if the crude oil leak area 700 increases in size, the length of the oil boom 600 needs to be increased, and the enclosure range correspondingly expanded to surround the crude oil leak area 700. If the crude oil leak area 700 moves, the oil boom 600 is also moved accordingly to ensure that the oil boom 600 always surrounds the crude oil leak area 700.

[0137] By predicting changes in the shape of the cracks, the changes in the oil spill area 700 can be predicted more accurately, and the setting of the oil boom 600 can be adjusted in a timely manner according to the changes, thereby reducing the pollution of the marine environment caused by the oil spill.

[0138] In some optional embodiments, determining the flow path 320 and flow velocity after the crude oil leak based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, and the sediment depth information includes: determining an initial path and an initial velocity based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, and the sediment depth information; obtaining a first dielectric constant of the crude oil, a second dielectric constant of the pure oil, and a third dielectric constant of the seawater; determining the water content of the crude oil based on the first dielectric constant, the second dielectric constant, and the third dielectric constant; and correcting the initial path and initial velocity based on the water content of the crude oil, the viscosity of the crude oil, and the density of the crude oil to obtain the flow path 320 and the flow velocity.

[0139] Specifically, the target leak location clearly defines the starting point of the crude oil leak. Ocean current information directly affects the initial direction and velocity of the crude oil in seawater. Seawater depth information determines the vertical movement space of the crude oil; deeper seawater causes the crude oil to experience greater pressure and fluid resistance during its ascent. Seawater density information interacts with crude oil density; when the crude oil density is greater than the seawater density, the crude oil will sink; conversely, it will rise. Sediment depth information can determine whether the crude oil will be blocked or affected by seabed sediment 310 after the leak. If the sediment 310 at the leak location is thick, the crude oil will be buried by the sediment 310 or its flow direction will be changed. A Lagrange or Eulerian model is used to describe the movement of the crude oil in seawater. Based on parameters such as the target leak location, ocean current velocity and direction, the initial path and velocity of the crude oil are calculated, yielding the initial path and initial velocity.

[0140] The dielectric constant is an electrical property of a material, used to measure its ability to store electrical energy under the influence of an electric field. The dielectric constant of crude oil, pure oil, and seawater can be measured using specialized equipment, relevant literature, industry standards, or databases; there are no specific limitations. Common measurement methods include the capacitance method, which involves measuring the capacitance of a capacitor containing the substance being tested and then calculating the dielectric constant using relevant formulas.

[0141] The water content of crude oil is determined based on the first, second, and third dielectric constants: the water content in crude oil affects its dielectric constant. Generally, the higher the water content, the greater the dielectric constant of the crude oil. This is because the dielectric constant of water is much greater than that of pure oil; when crude oil contains water, the overall dielectric constant will approach that of water.

[0142] The water content of crude oil is calculated using a model relating dielectric constant and water content. This is achieved by establishing a mathematical equation between the dielectric constant and water content to solve for the water content. For example, we can assume that the crude oil is a mixture of pure oil and water, and then use the water content calculation formula:

[0143]

[0144] Where, ε M Let ε be the dielectric constant of crude oil. W Let ε0 be the dielectric constant of water, ε0 be the dielectric constant of pure oil, and f0 be the dielectric constant of pure oil. W This refers to the moisture content.

[0145] Substituting the measured first, second, and third dielectric constants into the equation, the water content f can be solved. W .

[0146] Based on the calculated water content of the crude oil, and considering the relationship between the changes in crude oil viscosity and density, the initial path and initial velocity are corrected. The water content can be substituted as a parameter into the previously established mathematical model describing the movement of crude oil in seawater, and the flow path 320 and velocity of the crude oil can be recalculated. For example, in the fluid dynamics model, considering the influence of water content on the buoyancy of the crude oil (the higher the water content, the smaller the repulsive force between the crude oil and seawater, the higher the compatibility, and the smaller the buoyancy, thus reducing the flow velocity in seawater and correspondingly changing the flow path 320), the relevant parameters in the model are adjusted to obtain the corrected flow path 320 and flow velocity, which can more accurately describe the actual flow of crude oil in seawater.

[0147] In some alternative embodiments, refer to Figure 4Multiple monitoring devices 500 are installed between the buoy 200 and the ground 400. These devices collect image information of the designated area around the clock via image acquisition units. After triggering an oil spill alarm, they simultaneously activate image acquisition to automatically capture images of the accident site. The monitoring devices 500 also use oil spill detectors to detect oil spills. These detectors utilize the fluorescent properties of aromatic hydrocarbons in petroleum and its refined products to detect oil spills on the water surface. The detectors emit conical light pulses through a built-in ultraviolet emitter. When this ultraviolet light shines on the water surface, it excites oily substances to produce fluorescence of a specific wavelength. The fluorescence reflected back to the detector, along with the external light, is filtered through a multi-stage, specially designed system to remove stray and irrelevant spectra. After analysis by the built-in optical detection system, it can be determined whether the reflected light signal contains oil spill fluorescence information. If oil spill information is detected, an alarm is automatically sent to the monitoring center and on-duty personnel, enabling dock workers to quickly assess and respond appropriately to an oil spill incident. The monitoring equipment 500 is controlled via an RTU (Remote Terminal Unit). The RTU controls oil spill detectors and other monitoring devices, acquiring necessary data at set intervals and processing this data using internal algorithms to automatically determine if an oil spill has occurred. The RTU can remotely receive operation commands from the monitoring center to control the oil spill detectors and audible / visual alarms. For example, it can modify oil spill detector parameters (such as adjusting reference values ​​and offsets, monitoring time intervals, etc.) and automatically trigger on-site audible / visual alarms when an oil spill is detected. When acquiring images at night or in low-light conditions, the RTU automatically turns on its built-in LED lighting to compensate for insufficient surface illumination. The RTU control box has an automatic temperature and humidity monitoring function; when the temperature and humidity data are too high, it triggers a temperature and humidity alarm, prompting maintenance personnel to promptly open the box for inspection to ensure the normal operation of the equipment. The RTU integrates a GPS module and a vibration sensor module. When the external power supply is abnormally interrupted, the GPS location changes, or the vibration value exceeds the alarm value, the system automatically switches to battery power and simultaneously sends real-time equipment location and status information to the monitoring computer, maintaining real-time location tracking of the equipment. Figure 7 The monitoring equipment 500 and the RTU are installed using a mounting frame, which includes a main frame and a ground lock for securing the main frame. The main frame has a first mounting area, a second mounting area, and a third mounting area. The first mounting area is used to install an image acquisition device and / or other monitoring equipment; the second mounting area is used to install an oil spill detector and / or other monitoring equipment; and the third mounting area is used to install the RTU.

[0148] Implementing the embodiments of the present invention has the following beneficial effects: The embodiments of the present invention provide a method for detecting and handling crude oil leaks, comprising: acquiring crude oil leak information, wherein the crude oil leak information characterizes the leak information of an underwater crude oil pipeline, and the leak information indicates the target leak location and leak volume of the underwater crude oil pipeline; acquiring marine information, wherein the marine information characterizes ocean current information, seawater depth information, seawater density information, and sediment depth information from the underwater crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the underwater crude oil pipeline; determining a crude oil leak area 700 based on the crude oil leak information and the marine information, wherein the crude oil leak area 700 characterizes the area where the crude oil leaks to the sea surface; and setting up an oil boom 600 based on the crude oil leak area 700 to surround the crude oil leak area 700. By detecting the location and volume of the crude oil leak and determining the crude oil leak area 700 at the sea surface based on specific marine information, a corresponding oil boom 600 can be set up in advance based on the crude oil leak area 700 to contain the leaked crude oil, prevent the crude oil from spreading, and thus reduce marine pollution.

[0149] like Figure 8 As shown, in a second aspect, embodiments of the present invention also provide a computer device, which can be a terminal. The computer device includes a processor, a memory, and a network interface connected via a system bus. The memory may include a non-volatile storage medium and internal memory. The non-volatile storage medium may store an operating system and a computer program. The computer program includes program instructions, which, when executed, cause the processor to execute any industrial equipment visualization management method. The processor provides computing and control capabilities to support the operation of the entire computer device. The internal memory provides an environment for the execution of the computer program in the non-volatile storage medium; when executed by the processor, the computer program causes the processor to execute any industrial equipment visualization management method. The network interface is used for network communication, such as sending assigned tasks. Those skilled in the art will understand that... Figure 8 The structure shown is merely a block diagram of a portion of the structure related to the present disclosure and does not constitute a limitation on the computer equipment to which the present disclosure is applied. Specific computer equipment may include, for example, [the following is a list of possible additional structures]. Figure 8The processor may have more or fewer components, or combine certain components, or have different component arrangements. It should be understood that the processor can be a Central Processing Unit (CPU), but it can also be other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc. The general-purpose processor can be a microprocessor or any conventional processor. In one embodiment, the processor is configured to run a computer program stored in a memory to perform the following steps: acquiring crude oil leak information, wherein the crude oil leak information characterizes the leak information of an underwater crude oil pipeline, and the leak information indicates the target leak location and leak volume of the underwater crude oil pipeline; acquiring marine information, wherein the marine information characterizes ocean current information, seawater depth information, seawater density information, and sediment depth information from the underwater crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the underwater crude oil pipeline; determining a crude oil leak area 700 based on the crude oil leak information and the marine information, wherein the crude oil leak area 700 characterizes the area where the crude oil leaked and reached the sea surface; and setting up an oil boom 600 based on the crude oil leak area 700 so that the oil boom 600 surrounds the crude oil leak area 700.

[0150] It is evident that the content of the above method embodiments is applicable to this device embodiment. The specific functions implemented in this device embodiment are the same as those in the above method embodiments, and the beneficial effects achieved are also the same as those achieved in the above method embodiments.

[0151] Furthermore, this application also discloses a computer program product or computer program stored in a computer-readable storage medium. A processor of a computer device can read the computer program from the computer-readable storage medium, and the processor executes the computer program, causing the computer device to perform the described method. Similarly, the content of the above method embodiments is applicable to this storage medium embodiment. The specific functions implemented in this storage medium embodiment are the same as those in the above method embodiments, and the beneficial effects achieved are also the same as those achieved in the above method embodiments.

[0152] It is understood that all or some of the steps and systems in the methods disclosed above can be implemented as software, firmware, hardware, or suitable combinations thereof. Some or all of the physical components can be implemented as processors, such as central processing units, digital information processors, or microprocessors executing software, or as hardware, or as integrated circuits, such as application-specific integrated circuits. Such software can be distributed on computer-readable media, which can include computer storage media (or non-transitory media) and communication media (or transient media). As is known to those skilled in the art, the term computer storage media includes volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information (such as computer-readable instructions, data structures, program modules, or other data). Computer storage media includes, but is not limited to, RAM, ROM, EEPROM, flash memory or other memory technologies, CD-ROM, digital versatile disc (DVD) or other optical disc storage, magnetic cartridges, magnetic tape, disk storage or other magnetic storage devices, or any other medium that can be used to store desired information and is accessible to a computer. Furthermore, as is known to those skilled in the art, communication media typically contain computer-readable instructions, data structures, program modules, or other data in modulated data information such as carrier waves or other transmission mechanisms, and may include any information delivery medium.

[0153] The embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the present invention is not limited to the above embodiments. Within the scope of knowledge possessed by those skilled in the art, various changes can be made without departing from the spirit of the present invention.

Claims

1. A method for detecting and handling crude oil leaks, characterized in that, include: Acquire crude oil leak information, which characterizes the leak information of an underwater crude oil pipeline and indicates the target leak location and leak volume of the underwater crude oil pipeline; The marine information is acquired, which represents ocean current information, seawater depth information, seawater density information and sediment depth information from the subsea crude oil pipeline to the sea surface, and the sediment depth information indicates the sediment depth burying the subsea crude oil pipeline. The crude oil spill area is determined based on the crude oil spill information and the marine information, wherein the crude oil spill area represents the area where the crude oil reaches the sea level after the spill. An oil boom is set up according to the crude oil spill area so that the oil boom surrounds the crude oil spill area; Also includes: The ocean current scouring coefficient at the target leak location is determined based on the ocean current information. The crack change diagram of the crack shape is determined based on the crack shape of the underwater crude oil pipeline, the pressure difference between the inside and outside of the pipeline, the ocean current scouring coefficient, and the pipeline material. The leakage rate variation diagram at the target leakage location is determined based on the crack variation diagram. The corrected leakage area is obtained by correcting the crude oil leakage area in real time based on the leakage change diagram. The oil boom is set up according to the modified leak area so that the oil boom surrounds the crude oil at sea level, and the amount of crude oil in the oil boom is within a preset oil containment amount.

2. The method according to claim 1, characterized in that, Multiple vibration sensors are evenly installed on the underwater crude oil pipeline. The acquisition of crude oil leakage information includes: When the first sensor receives a first abrupt vibration signal, the second abrupt vibration signal of the second sensor is acquired. The first sensor represents the vibration sensor closest to the target leak location, the second sensor is adjacent to the first sensor, and the target leak location is located between the first sensor and the second sensor. The first leak location is determined based on the first abrupt vibration signal, the second abrupt vibration signal, and the position information of the first and second sensors; Acquire sonar information at the first leak location, the sonar information being obtained through a sonar device between the first sensor and the second sensor; The location of the target leak is obtained based on the sonar information; The leakage amount is determined based on the sonar information and pipeline parameter information, wherein the pipeline parameter information characterizes the pipeline diameter, pipeline roughness, pressure difference between the inside and outside of the pipeline, crude oil viscosity, and crude oil density of the subsea crude oil pipeline.

3. The method according to claim 2, characterized in that, Determining the first leak location based on the first abrupt vibration signal, the second abrupt vibration signal, and the position information of the first and second sensors includes: A first distance is determined based on the first position of the first sensor and the second position of the second sensor, wherein the first distance represents the distance between the first sensor and the second sensor on the underwater crude oil pipeline; The distance difference is determined based on the time difference and transmission speed of the first and second abrupt vibration signals, and the distance difference represents the difference between the second distance from the target leak location to the first sensor and the third distance from the target leak location to the second sensor; The first leak location is determined based on the distance difference and the first distance.

4. The method according to claim 2, characterized in that, The step of obtaining the target leak location based on the sonar information includes: A sonar map is obtained by labeling the sonar information. The underwater crude oil pipeline model was obtained based on the sonar map annotations. Identify defective areas on the underwater crude oil pipeline model and configure the defective areas as the target leak locations.

5. The method according to claim 4, characterized in that, Determining the leakage amount based on the sonar information and pipeline parameter information includes: After the defect area is marked based on the sonar information, the shape of the pipe crack in the defect area is extracted. The crude oil transport speed in the defect area is determined based on the pipe diameter, the pipe roughness, the crude oil viscosity, and the crude oil density. The leakage amount is determined based on the transport speed, the crack shape, the pressure difference between the inside and outside of the pipeline, the crude oil viscosity, and the crude oil density.

6. The method according to claim 1, characterized in that, The step of determining the oil spill area based on the oil spill information and the marine information includes: The flow path and velocity of the crude oil after the leak are determined based on the target leak location, ocean current information, seawater depth information, seawater density information, sediment depth information, and crude oil information, wherein the crude oil information includes crude oil viscosity, crude oil density, and crude oil water content. The point of crude oil leakage at sea level was determined based on the described flow path; The leakage time of crude oil at sea level is determined based on the flow velocity, wherein the leakage time characterizes the time it takes for crude oil to travel from the target leakage location to the leakage point; The crude oil leak area surrounding the leak point is determined based on the leak volume and the leak time.

7. The method according to claim 6, characterized in that, The step of determining the flow path and velocity of crude oil after the leak based on the target leak location, ocean current information, seawater depth information, seawater density information, and sediment depth information includes: The initial path and initial velocity are determined based on the target leak location, the ocean current information, the seawater depth information, the seawater density information, and the sediment depth information. The first dielectric constant of crude oil, the second dielectric constant of pure oil, and the third dielectric constant of seawater were obtained. The water content of the crude oil is determined based on the first dielectric constant, the second dielectric constant, and the third dielectric constant; The flow path and flow velocity are obtained by correcting the initial path and initial velocity based on the crude oil water content, crude oil viscosity, and crude oil density.

8. A computer device, wherein, The computer device includes a processor, a memory, and a computer program stored in the memory and executable by the processor, wherein the computer program, when executed by the processor, implements the steps of the method as described in any one of claims 1-7.

9. A computer-readable storage medium storing a processor-executable program, characterized in that, The processor-executable program, when executed by the processor, is used to perform the method as described in any one of claims 1-7.

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