Oil gas treatment delayed shutdown method and system, electronic equipment and medium

Abstract

The invention discloses an oil gas treatment delayed shutdown method and system, electronic equipment and a medium, and relates to the technical field of data processing. The method comprises the steps that the oil tank volume, the oil volume and the rated treatment capacity of an oil-gas treatment device are obtained, and the oil-gas space volume is calculated; after the processing device is started, the processed oil gas amount is calculated by monitoring the pressure and the operation time; when the pressure is reduced to the shutdown pressure for the first time, the remaining oil gas space volume is calculated; determining a pressure difference coefficient according to oil tank and pipeline parameters, and calculating an unrecovered oil gas quantity; calculating delayed downtime based on the unrecovered amount and the rated treatment amount; and finally, continuously operating the device according to the delay time to recover the residual oil gas, and stopping after timing is finished. According to the method, through accurate calculation and delay control, it is ensured that oil gas is fully recycled, and the recycling efficiency is improved. By implementing the technical scheme provided by the invention, the evaluation accuracy of the delayed shutdown opportunity of oil and gas treatment can be improved.

Description

Technical Field

[0001] This application relates to the field of data processing technology, specifically to a method, system, electronic device, and medium for delayed shutdown of oil and gas processing. Background Technology

[0002] As a crucial terminal for the sale of petroleum products, gas stations have received widespread attention for their environmental management. During refueling and unloading operations, the oil and gas vapors generated by petroleum evaporation, if directly released into the atmosphere, not only waste resources but also pollute the environment. Therefore, relevant national departments have formulated strict standards for oil and gas recovery, requiring gas stations to install oil and gas recovery systems to effectively collect and treat the evaporating oil and gas.

[0003] Currently, the commonly used oil and gas handling systems at gas stations mainly consist of oil and gas collection pipelines, oil and gas handling devices, and control systems. During system operation, the oil and gas handling device extracts and processes oil and gas from the tank using negative pressure suction. The control system monitors pipeline pressure changes and stops the oil and gas handling device when the pressure drops to a preset shutdown pressure value. The basic principle of this control method is that as a large amount of oil and gas is extracted from the tank, the pipeline pressure gradually decreases. When the pressure drops to a certain preset value, it indicates that the oil and gas in the tank has been largely processed, and stopping the device at this point avoids unnecessary energy consumption.

[0004] However, existing oil and gas handling control methods have a problem: due to the complexity of gas station pipeline systems and the physical characteristics of oil and gas flow, when the pipeline pressure drops to the preset shutdown pressure, a considerable amount of oil and gas remains in the system and is not completely recovered. The presence of this residual oil and gas is mainly due to uneven pressure distribution in various parts of the pipeline system. Existing control methods rely solely on single pressure monitoring to determine shutdown timing, often failing to consider the actual residual oil and gas situation throughout the system, thus reducing the accuracy of assessing delayed shutdown timing for oil and gas handling. Summary of the Invention

[0005] This application provides a method, system, electronic device, and medium for delayed shutdown of oil and gas processing, which can improve the accuracy of assessing the timing of delayed shutdown of oil and gas processing.

[0006] In a first aspect, this application provides a method for delayed shutdown of oil and gas processing equipment, including: Obtain the tank volume, liquid oil volume, and rated processing capacity of the oil and gas treatment device of the gas station, and calculate the oil and gas space volume based on the tank volume and the liquid oil volume; After starting the oil and gas processing device, monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the device, and calculate the volume of oil and gas that has been processed based on the rated processing capacity and the cumulative operating time of the device. When the pressure value of the pipeline pressure sensor is detected to drop to the preset shutdown pressure for the first time, the remaining oil and gas space volume is determined based on the oil and gas space volume and the processed oil and gas volume. The pressure differential coefficient is determined based on the tank geometry parameters and pipeline flow parameters of the gas station, and the volume of unrecovered oil and gas caused by pipeline flow pressure differential is calculated based on the remaining oil and gas space volume and the pressure differential coefficient. Calculate the delayed downtime based on the unrecovered oil and gas volume and the rated processing capacity; The delay timer is started according to the delay shutdown time. During the operation of the delay timer, the oil and gas treatment device is kept running to recover the unrecovered oil and gas volume. The oil and gas treatment device is stopped when the delay timer ends.

[0007] By adopting the above technical solution, the oil and gas space volume is calculated based on the tank volume and liquid oil volume. During the operation of the oil and gas treatment device, the pipeline pressure and cumulative operating time are monitored in real time. Then, the processed oil and gas volume is calculated based on the rated processing capacity and cumulative operating time. When the pipeline pressure is detected to drop to the preset shutdown pressure for the first time, the remaining oil and gas space volume is determined using the oil and gas space volume and the processed oil and gas volume. Next, the pressure difference coefficient is determined based on the gas station's tank geometry and pipeline flow parameters, and the unrecovered oil and gas volume caused by the pipeline flow pressure difference is calculated in conjunction with the remaining oil and gas space volume. Finally, the required delayed shutdown time is calculated based on the unrecovered oil and gas volume and the rated processing capacity. A delay timer controls the oil and gas treatment device to continue operating within this time to recover the unrecovered oil and gas. This solution, by considering the uneven pressure distribution in the pipeline system, accurately calculates the actual unrecovered oil and gas volume and determines a reasonable delayed shutdown time accordingly. This avoids the oil and gas residue problem that may occur if the shutdown timing is determined solely based on a single pressure value, thereby improving the accuracy of the assessment of the delayed shutdown timing for oil and gas treatment and achieving more complete oil and gas recovery.

[0008] Optionally, the difference between the oil tank volume and the liquid oil volume is multiplied by a preset gas-liquid conversion coefficient to obtain the initial oil-gas space volume under standard conditions; a temperature correction coefficient is determined based on the real-time temperature detected by the oil-gas temperature sensor; a pressure correction coefficient is determined based on the real-time pressure detected by the oil-gas pressure sensor; and the initial oil-gas space volume under standard conditions is corrected using the temperature correction coefficient and the pressure correction coefficient to obtain the corrected oil-gas space volume.

[0009] Optionally, the rated processing capacity is multiplied by the cumulative operating time of the device to obtain the theoretical processed oil and gas volume; the actual processing flow rate is detected in real time using a flow meter installed at the outlet of the oil and gas processing device; a processing efficiency correction coefficient is calculated based on the deviation between the actual processing flow rate and the rated processing capacity; when the processing efficiency correction coefficient is within a preset range, the theoretical processed oil and gas volume is used as the processed oil and gas volume; when the processing efficiency correction coefficient exceeds the preset range, the theoretical processed oil and gas volume is multiplied by the processing efficiency correction coefficient to obtain the corrected processed oil and gas volume.

[0010] Optionally, the following steps are taken: obtaining the gas phase density corresponding to the oil and gas space volume and the gas phase density corresponding to the processed oil and gas volume; calculating the oil and gas mass in the oil and gas space volume based on the gas phase density corresponding to the oil and gas space volume, and calculating the oil and gas mass in the processed oil and gas volume based on the gas phase density corresponding to the processed oil and gas volume; collecting the temperature and pressure of the space at the top of the oil tank; calculating the current gas phase density according to the temperature and pressure using a preset gas state equation; and dividing the mass difference between the oil and gas mass in the oil and gas space volume and the oil and gas mass in the processed oil and gas volume by the current gas phase density to obtain the remaining oil and gas space volume.

[0011] Optionally, the following steps are taken: obtaining the height and diameter of the oil tank and the geometric dimensions of the oil and gas recovery pipeline; obtaining the number of bends, bend angles, and pipe roughness of the oil and gas recovery pipeline; determining the local resistance coefficient of the pipeline based on the geometric dimensions, number of bends, and bend angles; determining the friction coefficient of the pipeline based on the pipe roughness; and multiplying the weighted sum of the local resistance coefficient and the friction coefficient by a correction term for the ratio of the oil tank's height to its diameter to obtain the differential pressure coefficient.

[0012] Optionally, the unrecovered oil and gas volume is divided by the rated processing capacity to obtain the theoretical delayed shutdown time; the pressure drop rate of the pipeline pressure sensor when it reaches the preset shutdown pressure is obtained; based on the pressure drop rate, the pipeline pressure drop value during the theoretical delayed shutdown time is predicted; the actual average processing flow rate during the delayed operation is calculated according to the pipeline pressure drop value and the pressure-flow characteristics of the oil and gas processing device; the theoretical delayed shutdown time is corrected based on the deviation between the actual average processing flow rate and the rated processing capacity to obtain the final delayed shutdown time.

[0013] Optionally, the delay timer is started in a countdown manner according to the delayed shutdown time, and the remaining delay time is updated at preset time intervals; during the operation of the delay timer, the current pressure value of the pipeline pressure sensor is monitored; when the current pressure value of the pipeline pressure sensor is detected to rise back to the preset shutdown pressure, the delay timer is reset, and the monitoring of the pressure value of the pipeline pressure sensor and the cumulative operating time of the device is repeated; when the countdown of the delay timer ends, a shutdown command is sent to the controller of the oil and gas processing device to stop the operation of the oil and gas processing device.

[0014] A second aspect of this application provides an oil and gas processing delayed shutdown system, the system comprising: The data acquisition module is used to acquire the tank volume, liquid oil volume, and rated processing capacity of the oil and gas processing device of the gas station, and to calculate the oil and gas space volume based on the tank volume and the liquid oil volume. The module for determining the volume of oil and gas processed is used to monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the device after the oil and gas processing device is started, and to calculate the volume of oil and gas processed based on the rated processing capacity and the cumulative operating time of the device. The module for determining the volume of unrecovered oil and gas is used to determine the remaining oil and gas space volume based on the oil and gas space volume and the processed oil and gas volume when the pressure value of the pipeline pressure sensor drops to the preset shutdown pressure for the first time; determine the pressure difference coefficient according to the geometric parameters of the oil tank and the pipeline flow parameters of the gas station; and calculate the unrecovered oil and gas volume caused by the pipeline flow pressure difference based on the remaining oil and gas space volume and the pressure difference coefficient. The delayed shutdown module is used to calculate the delayed shutdown time based on the unrecovered oil and gas volume and the rated processing capacity; start a delayed timer according to the delayed shutdown time; keep the oil and gas processing device running continuously during the operation of the delayed timer to recover the unrecovered oil and gas volume; and stop the oil and gas processing device when the delayed timer ends.

[0015] A third aspect of this application provides an electronic device including a memory, a processor, and a program stored in the memory and executable on the processor, the program being loaded and executed by the processor to implement a delayed shutdown method for oil and gas processing.

[0016] In a fourth aspect, this application provides a computer-readable storage medium storing a computer program that, when executed by a processor, causes the processor to implement a delayed shutdown method for oil and gas processing.

[0017] In summary, one or more technical solutions provided in this application have at least the following technical effects or advantages: By adopting the above technical solution, the oil and gas space volume is calculated based on the tank volume and liquid oil volume. During the operation of the oil and gas treatment device, the pipeline pressure and cumulative operating time are monitored in real time. Then, the processed oil and gas volume is calculated based on the rated processing capacity and cumulative operating time. When the pipeline pressure is detected to drop to the preset shutdown pressure for the first time, the remaining oil and gas space volume is determined using the oil and gas space volume and the processed oil and gas volume. Next, the pressure difference coefficient is determined based on the gas station's tank geometry and pipeline flow parameters, and the unrecovered oil and gas volume caused by the pipeline flow pressure difference is calculated in conjunction with the remaining oil and gas space volume. Finally, the required delayed shutdown time is calculated based on the unrecovered oil and gas volume and the rated processing capacity. A delay timer controls the oil and gas treatment device to continue operating within this time to recover the unrecovered oil and gas. This solution, by considering the uneven pressure distribution in the pipeline system, accurately calculates the actual unrecovered oil and gas volume and determines a reasonable delayed shutdown time accordingly. This avoids the oil and gas residue problem that may occur if the shutdown timing is determined solely based on a single pressure value, thereby improving the accuracy of the assessment of the delayed shutdown timing for oil and gas treatment and achieving more complete oil and gas recovery. Attached Figure Description

[0018] Figure 1 This is a schematic flowchart of an oil and gas processing delayed shutdown method provided in an embodiment of this application; Figure 2 This is a schematic diagram of the structure of an oil and gas processing delayed shutdown system provided in an embodiment of this application; Figure 3 This is a schematic diagram of the structure of an electronic device provided in an embodiment of this application.

[0019] Explanation of reference numerals in the attached drawings: 300, electronic device; 301, processor; 302, communication bus; 303, user interface; 304, network interface; 305, memory. Detailed Implementation

[0020] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this specification will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments.

[0021] In the description of the embodiments of this application, the words "for example" or "for instance" are used to indicate examples, illustrations, or explanations. Any embodiment or design that is described as "for example" or "for instance" in the embodiments of this application should not be construed as being more preferred or advantageous than other embodiments or design options. Rather, the use of the words "for example" or "for instance" is intended to present the relevant concepts in a specific manner.

[0022] In the description of the embodiments of this application, the term "multiple" means two or more. For example, multiple systems means two or more systems, and multiple screen terminals means two or more screen terminals. Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the indicated technical features. Thus, a feature defined with "first" or "second" may explicitly or implicitly include one or more of that feature. The terms "comprising," "including," "having," and variations thereof all mean "including but not limited to," unless otherwise specifically emphasized.

[0023] This application provides a method for delayed shutdown of oil and gas processing equipment. In one embodiment, please refer to... Figure 1 , Figure 1 This is a flowchart illustrating the oil and gas processing delayed shutdown method provided in this application embodiment. This method can be implemented using a computer program, which can be integrated into an application or run as a standalone utility application. The method can also be implemented using a microcontroller and can run on an oil and gas processing delayed shutdown system based on the von Neumann architecture. Specifically, the method may include the following steps: Step 101: Obtain the tank volume, liquid oil volume, and rated processing capacity of the oil and gas treatment device of the gas station, and calculate the oil and gas space volume based on the tank volume and liquid oil volume.

[0024] Among them, the oil tank volume refers to the total volume of the underground oil storage tanks at the gas station, which are used to store oil products such as gasoline and diesel; the liquid oil volume refers to the volume actually occupied by the liquid oil products stored in the oil tank, which is obtained in real time through equipment such as level gauges; the rated processing capacity of the oil and gas processing unit indicates the maximum volume of oil and gas that the oil and gas processing unit can process per hour under standard operating conditions, with the unit being cubic meters per hour; the oil and gas space volume refers to the space in the oil tank that is not occupied by liquid oil products, and this space is filled with an oil and gas mixture.

[0025] Specifically, this step is performed before the oil and gas processing unit is started. First, the total volume parameter of the oil tank is obtained through the oil tank management system; this parameter is usually a fixed value. Then, the liquid oil volume data displayed on the level gauge is read in real time; this data changes dynamically with operations such as refueling and unloading. Simultaneously, the rated processing capacity parameter is obtained from the oil and gas processing unit's nameplate or control system. Afterward, the liquid oil volume is subtracted from the oil tank volume to obtain the space volume occupied by the oil and gas. This calculation needs to consider the influence of environmental factors such as temperature and pressure on the gas state, therefore, appropriate corrections are required.

[0026] In some embodiments, the oil and gas space volume can be acquired and calculated in several ways: Optionally, various parameters can be directly acquired through an automatic tank metering system. This system includes a high-precision level gauge, temperature sensor, pressure sensor, etc., which can collect real-time data on level, temperature, and pressure within the tank and automatically calculate the oil and gas space volume using a built-in algorithm. The system performs temperature compensation and pressure correction on the raw data to ensure the accuracy of the calculation results. Finally, the corrected data is transmitted to the control system. Optionally, manual acquisition and calculation can be used. Operators first read the level data using on-site equipment, then consult the tank's technical parameter manual to obtain volume information, then collect temperature and pressure data using a portable measuring instrument, and finally manually calculate the oil and gas space volume based on the gas state equation and correction coefficients. It is understood that other methods can also be used to acquire and calculate the oil and gas space volume, such as online monitoring systems for oil and gas recovery, intelligent sensor networks, etc., which are not limited here.

[0027] Based on the above embodiments, as an optional embodiment, step 101, which calculates the oil and gas space volume based on the tank volume and the liquid oil volume, may further include the following steps: Step 201: Multiply the difference between the oil tank volume and the liquid oil volume by the preset gas-liquid conversion coefficient to obtain the initial oil-gas space volume under standard conditions.

[0028] The gas-liquid conversion coefficient refers to the ratio of oil to gas volume produced by the evaporation of a unit volume of liquid oil under standard conditions (temperature 20℃, pressure 101.325kPa). This coefficient is related to the quality and composition of the oil, and for gasoline it is usually between 1.1 and 1.3. The initial oil-gas space volume under standard conditions represents the theoretical volume value converted from the actual oil-gas space to the standard conditions.

[0029] Specifically, in practice, the total volume V1 of the oil tank and the current liquid oil volume V2 are first obtained, and the difference between them, ΔV = V1 - V2, is calculated to obtain the actual oil-gas space volume. Then, this difference is multiplied by a predetermined gas-liquid conversion coefficient k (e.g., 1.2), i.e., Vinitial = ΔV × k, to obtain the initial oil-gas space volume under standard conditions. Taking an oil tank with a volume of 50 cubic meters as an example, when the liquid oil volume is 30 cubic meters, the actual oil-gas space is 20 cubic meters. If the gas-liquid conversion coefficient is taken as 1.2, then the initial oil-gas space volume under standard conditions is 24 cubic meters. This conversion process considers the influence of the oil's volatility characteristics on the oil-gas volume.

[0030] Step 202: Determine the temperature correction coefficient based on the real-time temperature detected by the oil and gas temperature sensor; determine the pressure correction coefficient based on the real-time pressure detected by the oil and gas pressure sensor.

[0031] The temperature correction factor refers to the correction relationship between the actual temperature and the standard temperature (20℃), used to correct the impact of temperature changes on gas volume; the pressure correction factor refers to the correction relationship between the actual pressure and the standard pressure (101.325 kPa), used to correct the impact of pressure changes on gas volume. The oil and gas temperature sensor and pressure sensor are respectively installed in the top space of the oil tank for real-time monitoring of oil and gas temperature and pressure.

[0032] Specifically, during the oil and gas processing, the oil and gas temperature T is collected in real time by a temperature sensor and converted to Kelvin. The ratio of this converted temperature to the standard temperature T0 is the temperature correction factor KT = T / T0. Simultaneously, the oil and gas pressure P is collected by a pressure sensor, and the ratio of this converted pressure to the standard pressure P0 is the pressure correction factor KP = P0 / P. For example, when the actual temperature is detected as 30℃ (303.15K) and the actual pressure as 90kPa, the temperature correction factor KT = 303.15 / 293.15 ≈ 1.034, and the pressure correction factor KP = 101.325 / 90 ≈ 1.126. This correction method is based on the ideal gas law and considers the dual effects of temperature and pressure on gas volume.

[0033] Step 203: Correct the initial oil and gas space volume under standard conditions using temperature correction coefficient and pressure correction coefficient to obtain the corrected oil and gas space volume.

[0034] The corrected oil and gas space volume refers to the actual oil and gas space volume after temperature and pressure correction. This value more accurately reflects the actual state of oil and gas in the tank under the current operating conditions.

[0035] Specifically, during the correction calculation, the initial oil and gas space volume Vinitial under standard conditions is multiplied by the temperature correction factor KT and the pressure correction factor KP, respectively, i.e., Vcorrected = Vinitial × KT × KP, to obtain the corrected oil and gas space volume. Continuing the previous example, when Vinitial = 24 cubic meters, KT = 1.034, and KP = 1.126, the corrected oil and gas space volume Vcorrected = 24 × 1.034 × 1.126 ≈ 27.93 cubic meters. This correction process fully considers the difference between actual operating conditions and standard conditions, making the calculation results more consistent with reality. Through this correction, the amount of oil and gas to be processed in the tank can be accurately assessed, providing reliable data support for subsequent processing.

[0036] Step 102: After starting the oil and gas processing unit, monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the unit, and calculate the volume of oil and gas that has been processed based on the rated processing capacity and the cumulative operating time of the unit.

[0037] Among them, the pipeline pressure sensor refers to the sensing device installed on the oil and gas recovery pipeline to detect the oil and gas pressure in the pipeline, which is usually a capacitive or piezoelectric sensor; the cumulative running time of the device refers to the total running time of the oil and gas treatment device from the start to the current moment, in hours; the processed oil and gas volume represents the total amount of oil and gas actually processed by the oil and gas treatment device, in cubic meters.

[0038] Specifically, this step is continuously executed after the oil and gas processing unit starts up. First, pressure data within the pipeline is collected in real time using pipeline pressure sensors, typically at a sampling frequency of once per second, and the data is transmitted to the control system. Simultaneously, the control system starts a built-in timer to record the unit's operating time. While the unit is running continuously, the rated processing capacity is multiplied by the cumulative operating time to obtain the theoretical volume of oil and gas processed. For example, if an oil and gas processing unit has a rated processing capacity of 10 cubic meters per hour and has operated for 2 hours, the theoretical volume of oil and gas processed is 20 cubic meters. Furthermore, the actual processing capacity needs to be verified using a flow meter, and the theoretical value needs to be corrected based on the actual situation to ensure the accuracy of the calculation results.

[0039] In some embodiments, the volume of processed oil and gas can be calculated in several ways: Optionally, a theoretical calculation method can be used. First, the rated processing capacity parameters of the oil and gas processing unit are read. Then, the unit's operating time is recorded using a high-precision timer. Next, the two are multiplied to obtain the theoretical processing capacity. Finally, the theoretical value is corrected according to the operating status of the processing unit (such as operating frequency, load rate, etc.) to obtain a more accurate estimate of the processing capacity. Then, the processing capacity is compensated for based on changes in ambient temperature and pressure. Optionally, a measured calculation method can be used. High-precision flow meters are installed on the inlet and outlet pipelines of the oil and gas processing unit. The actual processing capacity is calculated by monitoring the difference between the inlet and outlet flow rates in real time. At the same time, operating parameters such as pipeline pressure and temperature are collected to correct the flow data. Finally, the corrected data is stored in the control system database. It is understood that other methods can also be used to calculate the volume of processed oil and gas, such as direct measurement using a mass flow meter or comprehensive calculation by combining data from multiple sensors. These methods are not limited here.

[0040] Based on the above embodiments, as an optional embodiment, step 102, which calculates the processed oil and gas volume based on the rated processing capacity and the cumulative operating time of the device, may further include the following steps: Step 301: Multiply the rated processing capacity by the cumulative operating time of the device to obtain the theoretical processed oil and gas volume; detect the actual processing flow rate in real time using a flow meter installed at the outlet of the oil and gas processing device; calculate the processing efficiency correction coefficient based on the deviation between the actual processing flow rate and the rated processing capacity.

[0041] Among them, the theoretical processed oil and gas volume represents the oil and gas processing capacity calculated based on the rated operating conditions; the actual processing flow rate refers to the actual oil and gas volume processed per hour by the oil and gas processing unit as measured by the flow meter; the processing efficiency correction coefficient represents the ratio of the actual processing efficiency to the theoretical efficiency, used to correct the deviation between the theoretical calculation value and the actual operating state.

[0042] Specifically, this step is performed continuously during the operation of the oil and gas processing unit. First, the rated processing capacity Q (unit: cubic meters per hour) is multiplied by the cumulative operating time t (unit: hours) to calculate the theoretical processed oil and gas volume = Q × t. For example, if the rated processing capacity is 15 cubic meters per hour and the unit has been running for 3 hours, the theoretical processed oil and gas volume is 45 cubic meters. Simultaneously, the actual processing flow rate q (unit: cubic meters per hour) is collected using a thermal mass flow meter installed at the outlet of the processing unit, with a sampling interval of 1 minute. The actual processing flow rate is compared with the rated processing capacity to calculate the processing efficiency correction factor k = q / Q. When the actual processing flow rate is 13 cubic meters per hour, the processing efficiency correction factor k = 13 / 15 ≈ 0.867. This calculation method fully considers the impact of the actual operating conditions of the unit on the processing efficiency.

[0043] Step 302: When the processing efficiency correction coefficient is within the preset range, the theoretical processed oil and gas volume is used as the processed oil and gas volume; when the processing efficiency correction coefficient exceeds the preset range, the theoretical processed oil and gas volume is multiplied by the processing efficiency correction coefficient to obtain the corrected processed oil and gas volume.

[0044] The preset range refers to the allowable fluctuation range of the processing efficiency correction coefficient, which is usually set to 0.85-1.15; the corrected processed oil and gas volume represents the processing volume that is closer to the actual situation after efficiency correction.

[0045] Specifically, this step is executed immediately after the processing efficiency correction coefficient is calculated. The control system first determines whether the processing efficiency correction coefficient k is within a preset range. When 0.85 ≤ k ≤ 1.15, it indicates that the device is operating stably and the actual processing efficiency is close to the theoretical efficiency; the theoretical processed oil and gas volume Vli is directly used as the final result. When k < 0.85 or k > 1.15, it indicates that the device's operating efficiency has deviated significantly and a correction calculation is required. The theoretical processed oil and gas volume is multiplied by the processing efficiency correction coefficient to obtain the corrected processed oil and gas volume. For example, when the theoretical processed oil and gas volume is 45 cubic meters and the processing efficiency correction coefficient is 0.867, the corrected processed oil and gas volume is 45 × 0.867 = 39.015 cubic meters. This correction mechanism ensures the accuracy of the processing volume calculation results and provides a reliable basis for subsequent control decisions.

[0046] Step 103: When the pressure value of the pipeline pressure sensor drops to the preset shutdown pressure for the first time, determine the remaining oil and gas space volume based on the oil and gas space volume and the processed oil and gas volume.

[0047] Among them, the preset shutdown pressure refers to the pressure threshold at which the oil and gas treatment device stops operating, which is usually set to a negative pressure value between -2kPa and -1kPa; the first drop refers to the moment when the pipeline pressure value first reaches the preset shutdown pressure; the remaining oil and gas space volume refers to the volume of oil and gas in the oil tank system that has not yet been treated when the shutdown pressure is first reached, and the unit is cubic meters.

[0048] Specifically, this step involves continuously monitoring pipeline pressure during the oil and gas processing. Execution is triggered when the pressure sensor detects that the pipeline pressure has first dropped to the preset shutdown pressure. First, the current oil and gas space volume V1 and the processed oil and gas volume V2 are obtained; the difference between the two is the remaining oil and gas space volume = V1 - V2. During the calculation, the two volume values ​​need to be standardized to the same temperature and pressure conditions. For example, when the oil and gas space volume is 100 cubic meters and the processed oil and gas volume is 80 cubic meters, the remaining oil and gas space volume is 20 cubic meters. This calculation result reflects the actual remaining amount of oil and gas to be processed in the system, providing basic data for determining the subsequent delayed shutdown time. The calculation also needs to consider the impact of oil and gas density changes on volume, using gas equations for operating condition correction to ensure the accuracy of the calculation results.

[0049] In some embodiments, the remaining oil and gas space volume can be determined in several ways: Optionally, the mass conservation method is used. First, the initial mass of the oil and gas in the oil and gas space is measured, then the mass of the processed oil and gas is measured. The difference between the two is divided by the oil and gas density under the current operating conditions to obtain the remaining oil and gas space volume. During this process, temperature and pressure data need to be collected in real time, and the oil and gas density is calculated using the gas equation of state. Finally, temperature and pressure compensation is performed on the calculation results. Optionally, the volumetric accumulation method is used. The changes in the oil tank level are continuously monitored by a high-precision level gauge to calculate the dynamic change value of the oil and gas space volume. At the same time, the processed oil and gas volume is accumulated and calculated by a flow meter. The remaining oil and gas space volume is obtained based on the real-time difference between the two volume values. The influence of environmental factors is considered during the calculation process, and the data is corrected accordingly. It is understood that other methods can also be used to determine the remaining oil and gas space volume, such as the combined sensor method, pressure balance method, etc., which are not limited here.

[0050] Based on the above embodiments, as an optional embodiment, step 103, determining the remaining oil and gas space volume based on the oil and gas space volume and the processed oil and gas volume, may further include the following steps: Step 401: Obtain the gas phase density corresponding to the oil and gas space volume and the gas phase density corresponding to the processed oil and gas volume; calculate the oil and gas mass in the oil and gas space volume based on the gas phase density corresponding to the oil and gas space volume, and calculate the oil and gas mass in the processed oil and gas volume based on the gas phase density corresponding to the processed oil and gas volume.

[0051] Among them, gas phase density refers to the mass of oil and gas per unit volume, with the unit being kilograms per cubic meter, and is related to operating parameters such as temperature and pressure; the gas phase density corresponding to the oil and gas space volume represents the density of oil and gas in the space at the top of the oil tank; the gas phase density corresponding to the processed oil and gas volume represents the density of the processed oil and gas during processing; and oil and gas mass refers to the total mass contained in a specific volume of oil and gas, with the unit being kilograms.

[0052] Specifically, this step is performed before determining the remaining oil and gas space volume. First, the real-time temperature T1 and pressure P1 of the oil and gas space are obtained. The gas phase density ρ1 corresponding to the oil and gas space volume is calculated using the gas equation ρ1 = MP1 / (RT1), where M is the average molecular weight of the oil and gas, and R is the universal gas constant. Simultaneously, the temperature T2 and pressure P2 of the processed oil and gas are obtained, and the gas phase density ρ2 corresponding to the processed oil and gas volume is calculated as ρ2 = MP2 / (RT2). Then, the oil and gas space volume V1 is multiplied by the corresponding gas phase density ρ1 to obtain the oil and gas mass m1 = V1 × ρ1 in the oil and gas space. Similarly, the processed oil and gas volume V2 is multiplied by the corresponding gas phase density ρ2 to obtain the processed oil and gas mass m2 = V2 × ρ2. For example, when the volume of the oil and gas space is 100 cubic meters and the corresponding gas phase density is 2.5 kg / cubic meter, the mass of the oil and gas in the oil and gas space is 250 kg; when the volume of the processed oil and gas is 80 cubic meters and the corresponding gas phase density is 2.3 kg / cubic meter, the mass of the processed oil and gas is 184 kg.

[0053] Step 402: Collect the temperature and pressure of the space at the top of the oil tank; calculate the current gas phase density based on the temperature and pressure using a preset gas equation.

[0054] The top space of the oil tank refers to the area above the liquid surface in the oil tank that is filled with oil and gas; the preset gas state equation refers to the mathematical equation describing the relationship between gas state parameters (pressure, volume, temperature, density), and the commonly used ideal gas state equation PV=nRT, where P is pressure, V is volume, n is amount of substance, R is gas constant, and T is absolute temperature; the current gas phase density represents the mass of oil and gas per unit volume under the current temperature and pressure conditions.

[0055] Specifically, this step is performed before calculating the remaining oil and gas volume. The oil and gas temperature T (in K) is collected by a temperature sensor installed on the top of the tank, and the oil and gas pressure P (in Pa) is collected by a pressure sensor. The collected temperature and pressure data are substituted into the gas equation ρ = MP / (RT), where M is the average molecular weight of the oil and gas (in kg / mol) and R is the universal gas constant (8.314 J / (mol·K)) to calculate the gas phase density ρ (in kg / m³) under the current operating conditions. For example, when the measured temperature is 293 K (20 °C), the pressure is 101325 Pa (1 standard atmosphere), and the average molecular weight of the oil and gas is 58 g / mol, the calculated current gas phase density is approximately 2.4 kg / m³.

[0056] Step 403: Divide the mass difference between the oil and gas mass in the oil and gas space volume and the oil and gas mass in the processed oil and gas volume by the current gas phase density to obtain the remaining oil and gas space volume.

[0057] The mass difference represents the difference between the total mass of oil and gas in the oil and gas space and the mass of oil and gas that has been processed, in kilograms; the remaining oil and gas space volume represents the volume value corresponding to the current operating conditions after converting the mass difference, in cubic meters.

[0058] Specifically, this step is performed after obtaining the current gas phase density. First, the oil-gas mass difference Δm is calculated, which is obtained by subtracting the processed oil-gas mass m2 from the oil-gas mass m1 in the oil-gas space, resulting in Δm = m1 - m2. Then, the mass difference Δm is divided by the current gas phase density ρ to obtain the remaining oil-gas space volume V_remaining = Δm / ρ. This calculation method considers the changes in gas state under different operating conditions, making the calculation results more consistent with reality. For example, when the oil-gas mass in the oil-gas space is 250 kg, the processed oil-gas mass is 184 kg, and the current gas phase density is 2.4 kg / m³, the remaining oil-gas space volume is (250 - 184) / 2.4 ≈ 27.5 m³.

[0059] Step 104: Determine the differential pressure coefficient based on the gas station's tank geometry and pipeline flow parameters, and calculate the volume of unrecovered oil and gas caused by pipeline flow differential pressure based on the remaining oil and gas space volume and differential pressure coefficient.

[0060] Among them, the oil tank geometric parameters represent the structural dimensional characteristics of the oil tank, including height, diameter, etc.; the pipeline flow parameters refer to the physical quantities that describe the flow characteristics of oil and gas in the pipeline, including pipeline diameter, length, number of bends, roughness, etc.; the pressure difference coefficient represents the relationship coefficient between pressure loss and flow resistance in the pipeline system; and the unrecovered oil and gas volume refers to the volume of oil and gas that cannot be recovered by the treatment device due to pipeline pressure difference.

[0061] Specifically, this step is executed after determining the volume of the remaining oil and gas space. First, obtain the height H and diameter D of the oil tank, as well as the inner diameter d, total length L, number of elbows n, elbow angle θ, and pipe inner wall roughness ε of the oil and gas recovery pipeline. Calculate the local resistance coefficient ξ and the friction factor λ of the pipeline based on these parameters. The local resistance coefficient is mainly caused by the elbows, and the calculation formula is ξ = Σ(0.946sin²(θ / 2))×n; the friction factor is related to the pipe roughness and Reynolds number Re, and is calculated through the Colebrook formula: 1 / √λ = -2lg(ε / (3.7d) + 2.51 / (Re√λ)). Combine these resistance coefficients to obtain the pressure difference coefficient K = (ξ + λL / d)×(H / D). Finally, multiply the volume V of the remaining oil and gas space by the pressure difference coefficient K to obtain the volume of unrecovered oil gas V_unrecovered = V×K. For example, when the volume of the remaining oil and gas space is 20 cubic meters and the calculated pressure difference coefficient is 0.15, the volume of unrecovered oil gas is 3 cubic meters.

[0062] In some embodiments, the determination of the pressure difference coefficient and the calculation of the volume of unrecovered oil gas can be achieved in various ways: Optionally, the theoretical calculation method is adopted. First, measure the geometric size parameters of the oil tank and the pipeline; then calculate each local resistance and friction resistance through fluid mechanics formulas; then establish a pressure loss model to calculate the pressure difference coefficient; finally, multiply the pressure difference coefficient by the volume of the remaining oil and gas space to obtain the unrecovered amount. Optionally, the experimental calibration method is adopted. Measure the pressure values at various points of the pipeline under different working conditions; record the flow data corresponding to the working conditions; establish a relationship curve between pressure loss and flow rate; determine the pressure difference coefficient according to the curve slope; use this coefficient to calculate the volume of unrecovered oil gas. It can be understood that other methods can also be used to determine the pressure difference coefficient and calculate the volume of unrecovered oil gas, such as numerical simulation methods, empirical formula methods, etc., which are not limited here.

[0063] Based on the above embodiments, as an optional embodiment, in step 104: Determining the pressure difference coefficient according to the geometric parameters of the oil tank and the pipeline flow parameters of the gas station, this step may further include the following steps: Step 501: Obtain the height, diameter of the oil tank, and geometric size parameters of the oil and gas recovery pipeline; obtain the number of elbows, elbow angle, and pipe roughness of the oil and gas recovery pipeline.

[0064] Among them, the height of the oil tank represents the vertical distance from the bottom to the top of the oil tank, with the unit of meter; the diameter of the oil tank represents the diameter size of the cross-section of the oil tank, with the unit of meter; the geometric size parameters include basic dimensions such as the inner diameter of the pipeline, the length of the pipeline, and the cross-sectional area; the number of elbows represents the total number of bent parts in the oil and gas recovery pipeline; the elbow angle represents the turning angle of the pipeline center line at each elbow, with the unit of degree; the pipe roughness represents the unevenness of the inner wall surface of the pipeline, with the unit of millimeter.

[0065] Specifically, this step is performed before determining the differential pressure coefficient. The tank height H (typically 3-4 meters) and diameter D (typically 2-3 meters) are obtained by consulting the tank design drawings. The vapor recovery pipeline is measured on-site, and the inner diameter d (typically 50-100 mm) and total length L (varies depending on the site layout) are recorded. The total number of bends n in the pipeline (including 90-degree bends and other angled bends) is counted, and the turning angle θ of each bend is measured. The absolute roughness ε of the pipeline inner wall is determined using a pipe roughness measuring instrument (typically 0.02-0.05 mm). For example, a gas station's tank is 3.5 meters high and 2.5 meters in diameter. The vapor recovery pipeline has an inner diameter of 80 mm, a total length of 15 meters, contains four 90-degree bends, and has a pipe roughness of 0.03 mm.

[0066] Step 502: Based on the geometric parameters, number of bends, and bend angle of the oil and gas recovery pipeline, determine the local resistance coefficient of the pipeline; based on the pipeline roughness, determine the friction coefficient of the pipeline; multiply the weighted sum of the local resistance coefficient and the friction coefficient by the ratio correction term of the height to the diameter of the oil tank to obtain the differential pressure coefficient.

[0067] Among them, the local resistance coefficient of the pipeline represents the ratio of flow resistance to flow kinetic energy caused by local components of the pipeline (such as elbows); the friction coefficient of the pipeline represents the ratio of flow resistance to flow kinetic energy caused by straight sections of the pipeline; the weighted sum represents the summation of the local resistance coefficient and the friction coefficient according to certain weights; the ratio correction term is used to correct the influence of the oil tank geometry on the pressure difference.

[0068] Specifically, this step is performed after all geometric parameters are obtained. First, based on the number of bends n and the bend angle θ, the local resistance coefficient ξ is calculated using the empirical formula ξ = Σ(0.946sin²(θ / 2)) × n. For a 90-degree bend, sin²(θ / 2) = 0.5, so the local resistance coefficient for each 90-degree bend is 0.473. Then, based on the pipe's Reynolds number Re and relative roughness ε / d, the friction coefficient λ is calculated using the Kolbroek formula. The local resistance coefficient ξ and the friction coefficient λ are weighted and summed, i.e., ξ + λL / d. Finally, multiplying by the ratio of tank height to diameter H / D as a correction term, the final pressure differential coefficient K = (ξ + λL / d) × (H / D) is obtained. For example, when the calculated local resistance coefficient is 1.892 (4 90-degree bends), the friction coefficient is 0.025, and H / D=1.4, the pressure difference coefficient K=(1.892+0.025×15 / 0.08)×1.4≈8.4.

[0069] Step 105: Calculate the delayed downtime based on the unrecovered oil and gas volume and the rated processing capacity.

[0070] Among them, delayed shutdown time refers to the time interval from the first reaching of the preset shutdown pressure to the final shutdown, in minutes; unrecovered oil and gas volume refers to the volume of oil and gas that has not been treated due to pipeline pressure difference, in cubic meters; rated processing capacity refers to the processing capacity of the oil and gas treatment device under standard operating conditions, in cubic meters per hour.

[0071] Specifically, this step is performed after the unrecovered oil and gas volume is calculated. First, the unrecovered oil and gas volume Vunrecovered is divided by the rated processing capacity Q of the oil and gas treatment unit to obtain the theoretical delayed shutdown time ttheoretical = Vunrecovered / Q × 60 (converted to minutes). Then, based on the pressure change data collected by the pressure sensor, the pressure drop rate ΔP / Δt at the preset shutdown pressure is calculated. Based on the pressure drop rate, the pipeline pressure change trend during the delayed operation is predicted. Through the pressure-flow characteristic curve of the oil and gas treatment unit, the actual processing capacity at different pressures is determined, and the average processing flow rate Qactual during the delayed operation is calculated. Finally, the unrecovered oil and gas volume is divided by the actual average processing flow rate to obtain the corrected delayed shutdown time tcorrected = Vunrecovered / Qactual × 60. For example, when the unrecovered oil and gas volume is 3 cubic meters, the rated processing capacity is 10 cubic meters per hour, and the actual average processing flow rate is 8 cubic meters per hour, the corrected delayed shutdown time is 3 / 8 × 60 = 22.5 minutes.

[0072] In some embodiments, the delayed shutdown time can be calculated in several ways: Optionally, a dynamic prediction method is used. First, a baseline delay time is calculated based on the unrecovered oil and gas volume and the rated processing capacity. Then, the pressure change rate and processing flow rate are monitored in real time. Next, a pressure-time prediction model is established. The delay time is dynamically adjusted based on the prediction model. Finally, an optimized delayed shutdown command is output. Optionally, a segmented calculation method is used. First, the delay process is divided into multiple time periods. Then, the pressure and flow rate of each time period are calculated independently. Next, the processing capacity of each time period is accumulated. When the accumulated processing capacity reaches the unrecovered oil and gas volume, the delay time is determined. Finally, the calculation result is corrected. It is understood that other methods can also be used to calculate the delayed shutdown time, such as fuzzy control methods, neural network prediction methods, etc., which are not limited here.

[0073] Based on the above embodiments, as an optional embodiment, step 105, which calculates the delayed shutdown time based on the unrecovered oil and gas volume and the rated processing capacity, may further include the following steps: Step 601: Divide the volume of unrecovered oil and gas by the rated processing capacity to obtain the theoretical delayed shutdown time; obtain the pressure drop rate of the pipeline pressure sensor when the preset shutdown pressure is reached; based on the pressure drop rate, predict the pipeline pressure drop value within the theoretical delayed shutdown time.

[0074] Among them, the pressure-flow characteristic represents the relationship between the processing capacity of the oil and gas processing unit under different pipeline pressures; the actual average processing flow rate refers to the actual processing capacity after considering the influence of pressure changes, and the unit is cubic meters per hour; the theoretical delayed downtime refers to the initial delayed time value calculated based on the rated processing capacity, and the unit is minutes; the final delayed downtime represents the actual delayed time value after correction, and the unit is minutes.

[0075] Specifically, this step is performed after the predicted pressure drop. First, the pressure-flow characteristic curve of the oil and gas processing unit is obtained, reflecting its processing capacity at different pressures. Using the predicted pressure drop, the processing flow rate corresponding to each pressure point during the extended operation period is obtained from the characteristic curve, and the average value is calculated to obtain the actual average processing flow rate. For example, when the predicted pressure drops from -2 kPa to -3.8 kPa, the corresponding processing flow rate drops from 10 cubic meters per hour to 7 cubic meters per hour, so the actual average processing flow rate is approximately 8.5 cubic meters per hour. Then, the ratio of the actual average processing flow rate to the rated processing capacity is calculated, and the actual average processing flow rate is divided by the rated processing capacity to obtain a correction factor. Finally, the theoretical delayed shutdown time is divided by the correction factor to obtain the final delayed shutdown time. When the theoretical delay time is 18 minutes, the actual average processing flow rate is 8.5 cubic meters per hour, and the rated processing capacity is 10 cubic meters per hour, the correction factor is 0.85, and the final delayed shutdown time is 21.2 minutes. This correction considers the impact of pressure changes on processing capacity, making the delay time more consistent with actual conditions.

[0076] Step 602: Calculate the actual average processing flow during the extended operation period based on the decrease in pipeline pressure and the pressure-flow characteristics of the oil and gas processing unit.

[0077] Among them, the pipeline pressure drop value represents the expected reduction in pipeline pressure within the theoretical delay time, in kilopascals; the pressure-flow characteristic represents the processing capacity relationship curve of the oil and gas processing unit under different pressure conditions; the delayed operation period refers to the time period from the first reaching the preset shutdown pressure to the final shutdown; the actual average processing flow rate represents the actual oil and gas processing capacity during the delayed operation period, in cubic meters per hour.

[0078] Specifically, this step is performed after obtaining the predicted pressure drop value. First, based on the predicted pressure drop value, the pressure variation range during the extended operation period is determined. For example, when the initial pressure is -2 kPa and the predicted pressure drop value is -1.8 kPa, the pressure variation range is -2 kPa to -3.8 kPa. Then, this pressure range is divided into multiple pressure points (e.g., one point every 0.2 kPa). Using the pressure-flow characteristic curve of the oil and gas processing unit, the corresponding processing flow rate value for each pressure point is found. Taking a certain oil and gas processing unit as an example, the processing flow rate is 10 cubic meters per hour at -2 kPa, 8.5 cubic meters per hour at -2.8 kPa, and 7 cubic meters per hour at -3.8 kPa. Finally, the processing flow rate values ​​corresponding to all pressure points are arithmetically averaged to obtain the actual average processing flow rate during the extended operation period. In the above example, by arithmetically averaging the processing flow rates at different pressure points, the actual average processing flow rate is calculated to be 8.5 cubic meters per hour. This calculation method considers the dynamic impact of pressure changes on processing capacity, making the calculation results more accurately reflect the actual operating conditions.

[0079] Step 603: Based on the deviation between the actual average processing flow and the rated processing flow, the theoretical delayed downtime is corrected to obtain the final delayed downtime.

[0080] Among them, the actual average processing flow rate represents the actual oil and gas processing capacity during the delayed operation period, in cubic meters per hour; the rated processing capacity represents the processing capacity of the oil and gas processing unit under standard operating conditions, in cubic meters per hour; the deviation refers to the ratio of the difference between the actual average processing flow rate and the rated processing capacity; the theoretical delayed shutdown time represents the delay time initially calculated based on the rated processing capacity, in minutes; and the final delayed shutdown time represents the actual delayed time value after correction, in minutes.

[0081] Specifically, this step is performed after the actual average processing flow rate is calculated. First, the actual average processing flow rate is divided by the rated processing capacity to obtain a correction factor. For example, when the actual average processing flow rate is 8.5 cubic meters per hour and the rated processing capacity is 10 cubic meters per hour, the correction factor is 0.85. This indicates that the actual processing capacity is lower than the rated value, requiring an extended operating time. Then, the theoretical delayed shutdown time is divided by the correction factor to obtain the final delayed shutdown time. Taking a theoretical delay time of 18 minutes as an example, when the correction factor is 0.85, the final delayed shutdown time is 21.2 minutes. This correction ensures that even with a reduced actual processing capacity, the operating time is extended to complete the processing of unrecovered oil and gas. The calculation results are directly used to execute the delayed shutdown in the control system, ensuring the integrity of oil and gas processing. The corrected delay time fully considers the impact of actual operating conditions on processing capacity, improving the oil and gas recovery effect.

[0082] Step 106: Start the delay timer according to the delayed shutdown time. Keep the oil and gas treatment unit running continuously during the operation of the delay timer to recover the unrecovered oil and gas volume. Stop the oil and gas treatment unit when the delay timer ends.

[0083] Among them, the delay timer refers to the timing device used to control the delayed shutdown time; the delayed shutdown time refers to the time interval from the start of the delay timer to the stop of the oil and gas treatment device, in minutes; the oil and gas treatment device refers to the main equipment used to treat oil and gas, including components such as vacuum pumps and condensers; the unrecovered oil and gas volume refers to the remaining amount of oil and gas that needs to be treated during the delayed operation, in cubic meters; the end of timing indicates the moment when the delay timer counts down to zero.

[0084] Specifically, this step is executed after the final delayed shutdown time is calculated. First, the delayed shutdown time is input into the delay timer of the control system, and the countdown function is started. For example, when the delayed shutdown time is 21.2 minutes, the delay timer starts counting down from 21.2 minutes to 0. During the countdown, the control system maintains the operation of the oil and gas processing unit, continuously recovering oil and gas. The delay timer updates the remaining time display at fixed time intervals (e.g., 1 minute). When the delay timer finishes counting down, i.e., when the displayed time is 0, the control system sends a shutdown command to the oil and gas processing unit, shutting down the vacuum pump and related equipment, completing the entire delayed shutdown process. During operation, the control system continuously monitors the pipeline pressure. When it detects that the pressure has risen back to the preset shutdown pressure, it automatically resets the delay timer and restarts the delayed shutdown control process.

[0085] In some embodiments, delayed shutdown control can be implemented in several ways: Optionally, a single-time delay control method is used, where the delayed shutdown time is first set to a timer; then a countdown is started and the device is kept running; the remaining time and pipeline pressure are continuously monitored; a shutdown command is sent when the countdown ends; and finally, the device is confirmed to have completely stopped. Optionally, a segmented delay control method is used, where the delay time is first divided into multiple time periods; then countdown control is executed segment by segment; the pipeline pressure status is checked at the end of each segment; the decision to proceed to the next segment is made based on the pressure status; and finally, the device is shut down after all time periods have been completed. It is understood that other methods can also be used to implement delayed shutdown control, such as fuzzy control and adaptive control methods, which are not limited here.

[0086] Based on the above embodiments, as an optional embodiment, in step 106: starting a delay timer according to the delayed shutdown time, keeping the oil and gas treatment device running continuously during the operation of the delay timer to recover the unrecovered oil and gas volume, and stopping the oil and gas treatment device when the delay timer ends, this step may further include the following steps: Step 701: Start the delay timer in countdown mode according to the delayed shutdown time, and update the remaining delay time at preset time intervals.

[0087] Among them, countdown mode means that the countdown starts from the set time and decreases; delay timer refers to the timing device used to control the delay stop time; preset time interval means the fixed period for updating the remaining time, usually 1 minute; remaining delay time refers to the remaining time from the current moment to the delay stop, in minutes.

[0088] Specifically, this step is performed after the final delayed shutdown time is determined. First, the calculated delayed shutdown time (e.g., 21.2 minutes) is set into the delay timer. After the delay timer starts, it counts down, updating the displayed value every preset time interval (1 minute). For example, when the initial set time is 21.2 minutes, the first update shows 20.2 minutes, the second update shows 19.2 minutes, and so on. The display device uses a digital display, accurate to one decimal place. The control system records the updated remaining delay time in the database for operational status monitoring and anomaly handling. During the countdown, the delay timer continuously sends the current timing status signal to the control system to ensure the oil and gas processing unit maintains its operational status. When the displayed value updates to 0, the delay timer sends a timing end signal to the control system. The entire timing process uses a high-precision clock source to ensure timing accuracy.

[0089] Step 702: During the operation of the delay timer, monitor the current pressure value of the pipeline pressure sensor; when the current pressure value of the pipeline pressure sensor is detected to rise back to the preset shutdown pressure, reset the delay timer and re-execute the monitoring of the pressure value of the pipeline pressure sensor and the cumulative running time of the device.

[0090] Among them, the pipeline pressure sensor refers to the sensing device installed on the oil and gas recovery pipeline for measuring pressure; the current pressure value refers to the real-time measured pressure value inside the pipeline, in kilopascals; the preset shutdown pressure refers to the pressure threshold that triggers shutdown control, usually between -2 kilopascals and -1 kilopascals; reset means restoring the delay timer to its initial state; the cumulative running time of the device refers to the total running time of the oil and gas processing device from startup to the current moment.

[0091] Specifically, this step is executed after the delay timer begins its countdown. The control system continuously collects pressure data via pipeline pressure sensors, with a sampling period of 1 second. When a rising trend in pipeline pressure is detected, and the pressure value rises to the preset shutdown pressure, it indicates the presence of new untreated oil and gas in the system. For example, if the preset shutdown pressure is -2 kPa, and the current pressure rises from -3 kPa to -2 kPa, the control system immediately resets the delay timer, clears the original remaining delay time, and stops the countdown. After resetting, the control system restarts collecting pressure data and accumulating running time, recalculating the delayed shutdown time according to the same control logic. This dynamic adjustment mechanism ensures that all oil and gas are effectively treated. In the event of a pressure rise, even if the delay timer has already been running for a period of time, the delay control process will be restarted to prevent premature shutdown and oil and gas emissions.

[0092] Step 703: When the countdown of the delay timer ends, a shutdown command is sent to the controller of the oil and gas processing unit to stop the operation of the oil and gas processing unit.

[0093] Among them, the countdown of the delay timer ends, indicating that the timer display time has returned to zero; the controller of the oil and gas treatment unit refers to the electrical control unit that controls the operation of the oil and gas treatment unit; the shutdown command indicates the control signal that stops the operation of the oil and gas treatment unit; the shutdown of the oil and gas treatment unit means that the vacuum pump, condenser and other components in the unit have completely stopped working.

[0094] Specifically, this step is executed when the delay timer counts down to 0. When the delay timer displays 0, the control system first confirms that the current pipeline pressure is lower than the preset shutdown pressure, indicating that the oil and gas during the delayed operation period has been sufficiently processed. Then, the control system sends a shutdown command to the controller of the oil and gas processing unit, which contains the specific execution sequence of the shutdown operation. After receiving the shutdown command, the controller first shuts off the power to the vacuum pump, stopping the extraction of oil and gas from the pipeline; then it shuts off the refrigeration system of the condenser, stopping the oil and gas condensation process; finally, it closes the relevant valves, disconnecting the oil and gas processing unit from the pipeline system. The control system continuously monitors the operating status of each component until it confirms that all components have completely stopped operating. During the shutdown process, the control system records data such as the shutdown time, cumulative operating time, and processed oil and gas volume in the operation log for subsequent statistical analysis.

[0095] Reference Figure 2 This application provides an oil and gas processing delayed shutdown system, which includes: a data acquisition module, a processed oil and gas volume determination module, an unrecovered oil and gas volume determination module, and a delayed shutdown module, wherein: The data acquisition module is used to acquire the tank volume, liquid oil volume, and rated processing capacity of the oil and gas processing unit of the gas station, and to calculate the oil and gas space volume based on the tank volume and liquid oil volume. The module for determining the volume of oil and gas processed is used to monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the device after the oil and gas processing unit is started, and to calculate the volume of oil and gas processed based on the rated processing capacity and the cumulative operating time of the device. The module for determining the volume of unrecovered oil and gas is used to determine the remaining oil and gas volume based on the oil and gas space volume and the volume of oil and gas already processed when the pressure value of the pipeline pressure sensor drops to the preset shutdown pressure for the first time; it determines the differential pressure coefficient based on the geometric parameters of the oil tank and the pipeline flow parameters of the gas station, and calculates the volume of unrecovered oil and gas caused by the pipeline flow differential pressure based on the remaining oil and gas space volume and the differential pressure coefficient. The delayed shutdown module is used to calculate the delayed shutdown time based on the unrecovered oil and gas volume and the rated processing capacity; start the delayed timer according to the delayed shutdown time; keep the oil and gas processing unit running continuously during the operation of the delayed timer to recover the unrecovered oil and gas volume; and stop the oil and gas processing unit when the delayed timer ends.

[0096] Based on the above embodiments, the data acquisition module is further used to multiply the difference between the oil tank volume and the liquid oil volume by a preset gas-liquid conversion coefficient to obtain the initial oil-gas space volume under standard conditions; determine the temperature correction coefficient based on the real-time temperature detected by the oil-gas temperature sensor; determine the pressure correction coefficient based on the real-time pressure detected by the oil-gas pressure sensor; and correct the initial oil-gas space volume under standard conditions using the temperature correction coefficient and the pressure correction coefficient to obtain the corrected oil-gas space volume.

[0097] Based on the above embodiments, the processed oil and gas volume determination module is further used to multiply the rated processing capacity by the cumulative operating time of the device to obtain the theoretical processed oil and gas volume; to detect the actual processing flow rate in real time through a flow meter installed at the outlet of the oil and gas processing device; to calculate the processing efficiency correction coefficient based on the deviation between the actual processing flow rate and the rated processing capacity; when the processing efficiency correction coefficient is within a preset range, the theoretical processed oil and gas volume is used as the processed oil and gas volume; when the processing efficiency correction coefficient exceeds the preset range, the theoretical processed oil and gas volume is multiplied by the processing efficiency correction coefficient to obtain the corrected processed oil and gas volume.

[0098] Based on the above embodiments, the unrecovered oil and gas volume determination module is further used to obtain the gas phase density corresponding to the oil and gas space volume and the gas phase density corresponding to the processed oil and gas volume; calculate the oil and gas mass in the oil and gas space volume based on the gas phase density corresponding to the oil and gas space volume, and calculate the oil and gas mass in the processed oil and gas volume based on the gas phase density corresponding to the processed oil and gas volume; collect the temperature and pressure of the space at the top of the oil tank; calculate the current gas phase density according to the temperature and pressure through a preset gas equation; divide the mass difference between the oil and gas mass in the oil and gas space volume and the oil and gas mass in the processed oil and gas volume by the current gas phase density to obtain the remaining oil and gas space volume.

[0099] Based on the above embodiments, the unrecovered oil and gas volume determination module is also used to obtain the height and diameter of the oil tank and the geometric dimensions of the oil and gas recovery pipeline; obtain the number of bends, bend angles, and pipeline roughness of the oil and gas recovery pipeline; determine the local resistance coefficient of the pipeline based on the geometric dimensions, number of bends, and bend angles of the oil and gas recovery pipeline; determine the friction coefficient of the pipeline based on the pipeline roughness; and multiply the weighted sum of the local resistance coefficient and the friction coefficient by a correction term for the ratio of the height to the diameter of the oil tank to obtain the differential pressure coefficient.

[0100] Based on the above embodiments, the delayed shutdown module is also used to divide the unrecovered oil and gas volume by the rated processing capacity to obtain the theoretical delayed shutdown time; obtain the pressure drop rate of the pipeline pressure sensor when it reaches the preset shutdown pressure; predict the pipeline pressure drop value during the theoretical delayed shutdown time based on the pressure drop rate; calculate the actual average processing flow rate during the delayed operation period based on the pipeline pressure drop value and the pressure-flow characteristics of the oil and gas processing device; and correct the theoretical delayed shutdown time based on the deviation between the actual average processing flow rate and the rated processing capacity to obtain the final delayed shutdown time.

[0101] Based on the above embodiments, the delayed shutdown module is also used to start a delay timer in a countdown manner according to the delayed shutdown time, and update the remaining delay time at preset time intervals; during the operation of the delay timer, the current pressure value of the pipeline pressure sensor is monitored; when the current pressure value of the pipeline pressure sensor is detected to rise back to the preset shutdown pressure, the delay timer is reset, and the monitoring of the pressure value of the pipeline pressure sensor and the cumulative operating time of the device is resumed; when the countdown of the delay timer ends, a shutdown command is sent to the controller of the oil and gas processing device to stop the operation of the oil and gas processing device.

[0102] It should be noted that the above embodiments of the apparatus are only illustrated by the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the device can be divided into different functional modules to complete all or part of the functions described above. In addition, the apparatus and method embodiments provided in the above embodiments belong to the same concept, and the specific implementation process can be found in the method embodiments, which will not be repeated here.

[0103] This application also discloses an electronic device. (See reference...) Figure 3 , Figure 3 This is a schematic diagram of the structure of an electronic device disclosed in an embodiment of this application. The electronic device 300 may include: at least one processor 301, at least one network interface 304, a user interface 303, a memory 305, and at least one communication bus 302.

[0104] The communication bus 302 is used to enable communication between these components.

[0105] The user interface 303 may include a display interface and a camera interface. Optionally, the user interface 303 may also include a standard wired interface and a wireless interface.

[0106] The network interface 304 may optionally include a standard wired interface or a wireless interface (such as a Wi-Fi interface).

[0107] The processor 301 may include one or more processing cores. The processor 301 connects to various parts of the server using various interfaces and lines, and performs various server functions and processes data by running or executing instructions, programs, code sets, or instruction sets stored in the memory 305, and by calling data stored in the memory 305. Optionally, the processor 301 may be implemented using at least one hardware form of Digital Signal Processing (DSP), Field-Programmable Gate Array (FPGA), or Programmable Logic Array (PLA). The processor 301 may integrate one or a combination of several of the following: Central Processing Unit (CPU), Graphics Processing Unit (GPU), and modem. The CPU primarily handles the operating system, user interface graphics, and applications; the GPU is responsible for rendering and drawing the content required for display; and the modem handles wireless communication. It is understood that the modem may also not be integrated into the processor 301 and may be implemented as a separate chip.

[0108] The memory 305 may include random access memory (RAM) or read-only memory. Optionally, the memory 305 may include a non-transitory computer-readable storage medium. The memory 305 may be used to store instructions, programs, code, code sets, or instruction sets. The memory 305 may include a program storage area and a data storage area, wherein the program storage area may store instructions for implementing an operating system, instructions for at least one function (such as touch function, sound playback function, image playback function, etc.), instructions for implementing the above-described method embodiments, etc.; the data storage area may store data involved in the above-described method embodiments, etc. Optionally, the memory 305 may also be at least one storage device located remotely from the aforementioned processor 301. (Refer to...) Figure 3 The memory 305, which serves as a computer storage medium, may include an operating system, a network communication module, a user interface module, and an application program for a delayed shutdown method for oil and gas processing.

[0109] exist Figure 3In the illustrated electronic device 300, the user interface 303 is mainly used to provide an input interface for the user and to acquire user input data; while the processor 301 can be used to call an application program stored in the memory 305 for an oil and gas processing delayed shutdown method. When executed by one or more processors 301, the electronic device 300 performs one or more methods as described in the above embodiments. It should be noted that, for the foregoing method embodiments, for the sake of simplicity, they are all described as a series of actions. However, those skilled in the art should understand that this application is not limited to the described order of actions, because according to this application, some steps can be performed in other orders or simultaneously. Secondly, those skilled in the art should also understand that the embodiments described in the specification are all preferred embodiments, and the actions and modules involved are not necessarily essential to this application.

[0110] In the above embodiments, the descriptions of each embodiment have different focuses. For parts not described in detail in a certain embodiment, please refer to the relevant descriptions in other embodiments.

[0111] In the various embodiments provided in this application, it should be understood that the disclosed apparatus can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative; for instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be through some service interface; the indirect coupling or communication connection between apparatuses or units may be electrical or other forms.

[0112] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment according to actual needs.

[0113] Furthermore, the functional units in the various embodiments of this application can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit. The integrated unit can be implemented in hardware or as a software functional unit.

[0114] If the integrated unit is implemented as a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage device (CMD). Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a memory and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods of the various embodiments of this application. The aforementioned memory includes various media capable of storing program code, such as USB flash drives, portable hard drives, magnetic disks, or optical disks.

[0115] The above are merely exemplary embodiments of this disclosure and should not be construed as limiting the scope of this disclosure. Any equivalent changes and modifications made in accordance with the teachings of this disclosure shall still fall within the scope of this disclosure. Other embodiments of this disclosure will be readily apparent to those skilled in the art upon consideration of the specification and practical disclosure.

[0116] This application is intended to cover any variations, uses, or adaptations of this disclosure that follow the general principles of this disclosure and include common knowledge or customary techniques in the art not described in this disclosure. The specification and embodiments are to be considered exemplary only.

Claims

1. A method for delayed shutdown of oil and gas processing equipment, characterized in that, include: Obtain the tank volume, liquid oil volume, and rated processing capacity of the oil and gas treatment device of the gas station, and calculate the oil and gas space volume based on the tank volume and the liquid oil volume; After starting the oil and gas processing device, monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the device, and calculate the volume of oil and gas that has been processed based on the rated processing capacity and the cumulative operating time of the device. When the pressure value of the pipeline pressure sensor is detected to drop to the preset shutdown pressure for the first time, the remaining oil and gas space volume is determined based on the oil and gas space volume and the processed oil and gas volume. The pressure differential coefficient is determined based on the tank geometry parameters and pipeline flow parameters of the gas station, and the volume of unrecovered oil and gas caused by pipeline flow pressure differential is calculated based on the remaining oil and gas space volume and the pressure differential coefficient. Calculate the delayed downtime based on the unrecovered oil and gas volume and the rated processing capacity; The delay timer is started according to the delay shutdown time. During the operation of the delay timer, the oil and gas treatment device is kept running to recover the unrecovered oil and gas volume. The oil and gas treatment device is stopped when the delay timer ends.

2. The method for delayed shutdown of oil and gas processing according to claim 1, characterized in that, The calculation of the oil and gas space volume based on the oil tank volume and the liquid oil volume includes: Multiply the difference between the oil tank volume and the liquid oil volume by a preset gas-liquid conversion coefficient to obtain the initial oil-gas space volume under standard conditions. Determine the temperature correction factor based on the real-time temperature detected by the oil and gas temperature sensor; The pressure correction coefficient is determined based on the real-time pressure detected by the oil and gas pressure sensor. The initial oil and gas space volume under the standard conditions is corrected by the temperature correction coefficient and the pressure correction coefficient to obtain the corrected oil and gas space volume.

3. The method for delayed shutdown of oil and gas processing according to claim 1, characterized in that, The calculation of the processed oil and gas volume based on the rated processing capacity and the cumulative operating time of the device includes: Multiply the rated processing capacity by the cumulative operating time of the device to obtain the theoretical volume of oil and gas processed; The actual processing flow rate is detected in real time by a flow meter installed at the outlet of the oil and gas processing unit. Calculate the processing efficiency correction factor based on the deviation between the actual processing flow rate and the rated processing capacity; When the processing efficiency correction coefficient is within the preset range, the theoretical processed oil and gas volume is used as the processed oil and gas volume. When the processing efficiency correction coefficient exceeds the preset range, the theoretical processed oil and gas volume is multiplied by the processing efficiency correction coefficient to obtain the corrected processed oil and gas volume.

4. The method for delayed shutdown of oil and gas processing according to claim 1, characterized in that, Determining the remaining oil and gas space volume based on the oil and gas space volume and the processed oil and gas volume includes: Obtain the gas phase density corresponding to the oil and gas space volume and the gas phase density corresponding to the processed oil and gas volume; Based on the gas phase density corresponding to the oil and gas space volume, calculate the oil and gas mass in the oil and gas space volume, and based on the gas phase density corresponding to the processed oil and gas volume, calculate the oil and gas mass in the processed oil and gas volume. Collect temperature and pressure data from the top space of the oil tank; The current gas phase density is calculated based on the temperature and pressure using a preset gas equation. The remaining oil and gas space volume is obtained by dividing the mass difference between the oil and gas mass in the oil and gas space volume and the oil and gas mass in the processed oil and gas volume by the current gas phase density.

5. The method for delayed shutdown of oil and gas processing according to claim 1, characterized in that, The step of determining the differential pressure coefficient based on the gas station's tank geometry and pipeline flow parameters includes: Obtain the height, diameter, and geometric dimensions of the oil tank and the oil and gas recovery pipeline; Obtain the number of bends, bend angles, and pipe roughness of the oil and gas recovery pipeline; Based on the geometric dimensions, number of bends, and bend angles of the oil and gas recovery pipeline, the local resistance coefficient of the pipeline is determined. Based on the pipe roughness, determine the pipe friction coefficient; The pressure differential coefficient is obtained by multiplying the weighted sum of the local resistance coefficient and the friction resistance coefficient by a correction term for the ratio of the tank's height to its diameter.

6. The method for delayed shutdown of oil and gas processing according to claim 1, characterized in that, The calculation of the delayed downtime based on the unrecovered oil and gas volume and the rated processing capacity includes: Divide the volume of unrecovered oil and gas by the rated processing capacity to obtain the theoretical delayed downtime. The pressure drop rate of the pipeline pressure sensor when the preset shutdown pressure is reached is obtained; Based on the pressure drop rate, the pressure drop in the pipeline during the theoretical downtime is predicted; Calculate the actual average processing flow rate during the extended operation period based on the decrease in pipeline pressure and the pressure-flow characteristics of the oil and gas processing unit; Based on the deviation between the actual average processing flow and the rated processing flow, the theoretical delayed downtime is corrected to obtain the final delayed downtime.

7. The method for delayed shutdown of oil and gas processing according to claim 6, characterized in that, The step of starting a delay timer according to the delayed shutdown time, maintaining continuous operation of the oil and gas treatment device during the operation of the delay timer to recover the unrecovered oil and gas volume, and stopping the oil and gas treatment device when the delay timer ends includes: The delay timer is started in a countdown manner according to the specified delay shutdown time, and the remaining delay time is updated at preset time intervals; During the operation of the delay timer, the current pressure value of the pipeline pressure sensor is monitored; When the current pressure value of the pipeline pressure sensor is detected to rise back to the preset shutdown pressure, the delay timer is reset, and the monitoring of the pressure value of the pipeline pressure sensor and the cumulative running time of the device is restarted. When the countdown of the delay timer ends, a shutdown command is sent to the controller of the oil and gas processing device to stop the operation of the oil and gas processing device.

8. An oil and gas processing delayed shutdown system, characterized in that, The system includes: The data acquisition module is used to acquire the tank volume, liquid oil volume, and rated processing capacity of the oil and gas processing device of the gas station, and to calculate the oil and gas space volume based on the tank volume and the liquid oil volume. The module for determining the volume of oil and gas processed is used to monitor the pressure value of the pipeline pressure sensor and the cumulative operating time of the device after the oil and gas processing device is started, and to calculate the volume of oil and gas processed based on the rated processing capacity and the cumulative operating time of the device. The module for determining the volume of unrecovered oil and gas is used to determine the remaining oil and gas space volume based on the oil and gas space volume and the processed oil and gas volume when the pressure value of the pipeline pressure sensor drops to the preset shutdown pressure for the first time; determine the pressure difference coefficient according to the geometric parameters of the oil tank and the pipeline flow parameters of the gas station; and calculate the unrecovered oil and gas volume caused by the pipeline flow pressure difference based on the remaining oil and gas space volume and the pressure difference coefficient. The delayed shutdown module is used to calculate the delayed shutdown time based on the unrecovered oil and gas volume and the rated processing capacity; start a delayed timer according to the delayed shutdown time; keep the oil and gas processing device running continuously during the operation of the delayed timer to recover the unrecovered oil and gas volume; and stop the oil and gas processing device when the delayed timer ends.

9. An electronic device, characterized in that, The device includes a processor, a memory, a user interface, and a network interface. The memory is used to store instructions, the user interface and the network interface are used to communicate with other devices, and the processor is used to execute the instructions stored in the memory to cause the electronic device to perform the oil and gas processing delayed shutdown method as described in any one of claims 1-7.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores instructions that, when executed, perform the oil and gas processing delayed shutdown method as described in any one of claims 1-7.

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