Intelligent control system for gas-liquid separation of multiphase flow in gas well

Abstract

The application belongs to the technical field of oil and natural gas exploitation, and particularly discloses a gas well multiphase flow production gas liquid separation intelligent control system, which comprises a sand removal standard judgment module, an abnormal wellhead positioning module, an abnormal treatment closed loop module, a compression ratio optimization module, a flow pattern defoaming joint control module and a gas liquid separation control module. The application can accurately position the abnormal wellhead with substandard sand removal by monitoring the sand content of the collecting header in real time and combining the quantitative analysis of the abnormal contribution degree of the wellhead, and can avoid the substandard sand particles from entering the subsequent separator through secondary sand removal and standard verification, thereby reducing the abrasion and plugging risk of the equipment and prolonging the service life of the equipment. Meanwhile, the initial compression ratio is matched based on the gas liquid ratio, and the dynamic correction is performed in combination with the real-time pressure and temperature deviation, so that the compression ratio is ensured to be in the efficient operation interval of the multiphase compression device, and the excessive compression caused by the parameter fluctuation is avoided, and the compression efficiency is significantly improved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction technology and relates to an intelligent control system for gas-liquid separation in multiphase flow drainage of gas wells. Background Technology

[0002] Multiphase flow gas well production refers to the process of transporting a mixture of gas, liquid, and solid phases produced from the formation to a processing system via the wellbore and surface pipelines during gas well production. Due to the complex flow patterns of multiphase flow, its gas-liquid separation efficiency directly affects production safety and economics. Traditional separation systems generally suffer from three major bottlenecks: incomplete sand removal, low compression efficiency, and uncontrolled foaming. Therefore, intelligent control is needed to achieve efficient separation of the gas and liquid phases.

[0003] For example, Chinese invention patent CN111058814A discloses an intelligent injection system and method for gas well foam drainage and gas production. This system dynamically adjusts the dosage of defoamer / foaming agent by real-time acquisition of parameters from the gas production channel and the fluid production channel to increase gas production. The injection system directly and adaptively adjusts the injection timing based on changes in gas production, thereby improving gas well output.

[0004] The existing technologies mentioned above have the following shortcomings: 1. Currently, optimization is only applied to the defoamer and foaming agent injection process, and there is a lack of wellhead sand removal status monitoring and abnormal location mechanism, which leads to sand particles entering the separator and causing equipment wear. At the same time, sand particles interfere with the defoamer injection efficiency, resulting in a decrease in gas-liquid separation effect.

[0005] 2. The current separator has fixed gas and liquid phase volumes and does not dynamically adjust the volume distribution based on the real-time gas-liquid ratio and foam rate. This leads to problems such as insufficient gas phase volume causing foam entrainment and insufficient liquid phase volume affecting residence time. Consequently, gas-liquid separation is incomplete and separation efficiency is limited. At the same time, the imbalance in volume distribution will increase the equipment load and make it difficult to adapt to complex and variable multiphase flow conditions. Summary of the Invention

[0006] In view of this, in order to solve the problems mentioned in the background technology, a gas-liquid separation intelligent control system for multiphase flow drainage of gas wells is proposed.

[0007] The objective of this invention can be achieved through the following technical solution: This invention provides an intelligent control system for gas-liquid separation in multiphase flow drainage of gas wells, including: a desanding compliance determination module, which inputs the desanded gas from each wellhead into the main collection pipe, detects its sand content, and determines whether the desanding meets the standard.

[0008] If the abnormal wellhead location module fails to meet the standard, it detects the sand content in the output pipes of each wellhead, calculates the abnormal contribution based on the flow rates of the wellhead and the main pipe, and locates the abnormal wellhead.

[0009] The abnormal handling closed-loop module shuts down the abnormal wellhead output pipeline, starts secondary sand removal at the wellhead and verifies it, and restarts the output pipeline after the standard is met.

[0010] The compression ratio optimization module inputs qualified gas into the multiphase compression device, detects the pressure, gas-liquid ratio and temperature of the multiphase flow in the device, and determines the optimal compression ratio by combining it with preset compression characteristic rules.

[0011] The flow pattern defoaming control module, after executing the optimal compression ratio, inputs the compressed multiphase flow into the separator and detects the flow pattern of the compressed multiphase flow in the inlet pipe. Based on the flow pattern and the preset flow pattern-defoamer correlation, it sets the initial injection rate of the defoamer and detects the foam rate in the separator. If it exceeds the preset range, it adjusts the injection rate.

[0012] The gas-liquid separation control module detects the gas-liquid ratio, foam rate, liquid flow rate, gas pressure, and real-time liquid level in the separator, calculates the required gas and liquid volumes for separation, determines the gas outlet pressure setpoint and the liquid outlet control valve opening based on this, and executes the corresponding control.

[0013] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0014] (1) This invention accurately locates abnormal wellheads that fail to meet sand removal standards by real-time monitoring of the sand content in the main collection pipe and quantitative analysis of the contribution of wellhead anomalies. At the same time, through secondary sand removal and standard verification, it avoids excessive sand particles from entering the subsequent separator, thereby reducing the risk of equipment erosion and blockage, and thus extending the equipment life.

[0015] (2) The present invention ensures that the compression ratio is within the efficient operating range of the multiphase compression device by matching the initial compression ratio based on the gas-liquid ratio and dynamically correcting it in combination with real-time pressure and temperature deviations. This avoids over-compression caused by parameter fluctuations, significantly improves compression efficiency, and reduces energy consumption costs.

[0016] (3) This invention solves the problem that a single injection strategy is difficult to adapt to complex flow patterns by setting the initial injection rate of defoamer based on the flow pattern and adjusting it in real time according to the foam rate in the separator. At the same time, it avoids gas-liquid entrainment caused by excessive or insufficient foam, and effectively improves the purity of gas-liquid separation.

[0017] (4) The present invention calculates the theoretical volume of the gas phase and liquid phase by gas-liquid ratio and corrects it by combining foam rate and liquid phase residence time, so as to ensure that the gas phase and liquid phase volume distribution matches the real-time operating conditions. At the same time, the gas phase outlet pressure setting value and the liquid phase outlet control valve opening are dynamically adjusted, thereby maintaining the gas-liquid balance in the separator.

[0018] (5) This invention forms a closed-loop control through parameter linkage. The abnormal handling results affect the subsequent compression parameters. The flow pattern data guides the defoaming strategy. The separation of demand feeds back pressure and opening control, thereby reducing manual intervention. At the same time, the accurate location and individual handling of abnormal wellheads avoids the shutdown of the entire system for troubleshooting, significantly shortens the fault response time, and improves the overall production continuity. Attached Figure Description

[0019] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0020] Figure 1 This is a schematic diagram showing the connections of the various modules in the system of the present invention.

[0021] Figure 2 This is a schematic diagram of the abnormal wellhead positioning steps of the present invention.

[0022] Figure 3 This is a schematic diagram showing the connection steps for determining the opening degree of the liquid phase outlet control valve in this invention. Detailed Implementation

[0023] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0024] Please see Figure 1 As shown, the present invention provides an intelligent control system for gas-liquid separation in multiphase flow drainage of gas wells. The system includes: a sand removal standard determination module, an abnormal wellhead positioning module, an abnormal handling closed-loop module, a compression ratio optimization module, a flow pattern defoaming joint control module, and a gas-liquid separation control module.

[0025] In the above, the abnormal wellhead positioning module is connected to the sand removal standard judgment module and the abnormal handling closed-loop module, respectively. The compression ratio optimization module is connected to the abnormal handling closed-loop module and the flow pattern defoaming joint control module, respectively. The flow pattern defoaming joint control module is also connected to the gas-liquid separation control module.

[0026] The sand removal compliance determination module inputs the desanded gas from each wellhead into the main collection pipe, detects its sand content, and determines whether the sand removal meets the standard.

[0027] For example, determining whether the sand removal meets the standard includes comparing the sand content of the main collection pipe with a preset sand content threshold.

[0028] It should be added that the preset sand content critical value refers to the key threshold for determining whether the sand removal treatment at the wellhead meets the standard during the multiphase flow drainage process of gas wells, that is, the maximum sand content standard allowed in the collection main. Specifically, the preset sand content critical value is determined by statistically analyzing the historical peak sand content data of each wellhead and collection main in the block over the past three years, taking 80% of this as the initial critical value, and using a rolling update mechanism to incorporate newly generated peak data and remove historical data older than three years, dynamically calibrating the critical value to adapt to changes in formation sand production patterns during gas well production.

[0029] If the sand content in the main collection pipe is less than the preset critical sand content value, the sand removal is deemed to meet the standard; otherwise, the sand removal is deemed to fail to meet the standard.

[0030] If the abnormal wellhead location module is determined to be substandard, it detects the sand content in the output pipes of each wellhead, calculates the abnormal contribution based on the flow rates of the wellhead and the main pipe, and locates the abnormal wellhead.

[0031] Please see Figure 2 As shown, exemplarily, the method of locating abnormal wellheads includes: multiplying the sand content of each wellhead output pipe and the main collection pipe by its flow rate to obtain the sand content contribution value of each wellhead and the main collection pipe.

[0032] The abnormal contribution of each wellhead is calculated by comparing its sand content with that of the main collection pipe.

[0033] The abnormal contribution of each wellhead is compared with the preset abnormal contribution threshold, and wellheads with an abnormal contribution greater than the preset abnormal contribution threshold are selected as abnormal wellheads.

[0034] It should be added that the preset abnormal contribution threshold is a benchmark threshold used to determine whether the wellhead is abnormal. Its setting logic is as follows: the average abnormal contribution of each wellhead under normal operating conditions in historical production data is used as the preset abnormal contribution threshold to ensure that the abnormal contribution of the wellhead does not exceed this value under most normal operating conditions.

[0035] The abnormality handling closed-loop module shuts down the abnormal wellhead output pipeline, starts secondary sand removal at the wellhead and verifies it, and restarts the output pipeline after the standard is met.

[0036] This invention, through real-time monitoring of the sand content in the main collection pipe and quantitative analysis of the contribution of wellhead anomalies, accurately locates abnormal wellheads where sand removal is not up to standard. At the same time, through secondary sand removal and standard verification, it prevents excessive sand particles from entering the subsequent separator, thereby reducing the risk of equipment erosion and blockage, and thus extending the equipment life.

[0037] It should be added that the anomaly handling closed-loop module includes: when the abnormal wellhead is located, sending a shut-off command to the control valve of the abnormal wellhead output pipeline to cut off the delivery of fluid from the abnormal wellhead to the main collection pipe, so as to prevent the fluid with excessive sand content from continuing to enter the subsequent system.

[0038] For closed abnormal wellheads, their associated secondary desanding devices are activated to further desand the fluid produced from the wellhead, thereby enhancing the desanding effect and reducing the sand content.

[0039] During the secondary sand removal process, the sand content of the wellhead output pipeline is monitored in real time and compared with the preset sand content threshold to determine whether it meets the standard.

[0040] If the sand content after secondary sand removal is found to be lower than the preset critical sand content value, an opening command is sent to the control valve of the abnormal wellhead output pipeline to restart the pipeline delivery. If the standard is not met, the operation is repeated until the sand content meets the standard before restarting.

[0041] The compression ratio optimization module inputs qualified gas into the multiphase compression device, detects the pressure, gas-liquid ratio and temperature of the multiphase flow in the device, and determines the optimal compression ratio in combination with preset compression characteristic rules.

[0042] It should be added that the preset compression characteristic rule refers to the pre-set association rule for matching the gas-liquid ratio and the initial compression ratio based on the performance parameters and multiphase flow characteristics of the multiphase compression device. It includes the compression ratio range corresponding to different gas-liquid ratio intervals and serves as the benchmark for determining the initial compression ratio.

[0043] The process of setting the preset compression characteristic rules is as follows: for multiphase compression devices, the operating parameters under different compression ratios and the gas-liquid ratio range under the corresponding operating conditions are tested through experiments.

[0044] Based on the test data, the gas-liquid ratio is divided into several continuous intervals, and each interval is matched with a compression ratio.

[0045] Based on the device's design parameters, such as maximum or minimum allowable compression ratio and pressure tolerance range, the boundaries of the aforementioned intervals are corrected to ensure that the compression ratios involved in the rules do not exceed the device's safe operating range. The correspondence between the divided gas-liquid ratio intervals and the compression ratio is solidified into preset compression characteristic rules, serving as the benchmark for subsequent matching of the initial compression ratio.

[0046] For example, determining the optimal compression ratio includes: matching the gas-liquid ratio of the multiphase flow with the gas-liquid ratio range corresponding to each compression ratio in the preset compression characteristic rules to obtain the initial compression ratio of the multiphase flow.

[0047] Based on the deviation between the pressure and the preset pressure reference value, the initial compression ratio is pressure-corrected to obtain the pressure-corrected compression ratio.

[0048] It should be added that the pressure correction step for the initial compression ratio is as follows: based on the preset pressure reference value, the pressure deviation range is divided into high pressure deviation range, normal deviation range and low pressure deviation range. A corresponding pressure correction coefficient is matched for each pressure deviation range. The high pressure deviation range corresponds to a correction coefficient less than 1, the normal deviation range corresponds to a correction coefficient equal to 1, and the low pressure deviation range corresponds to a correction coefficient greater than 1. When the pressure is too high, the compression ratio is reduced, and when the pressure is too low, the compression ratio is increased.

[0049] Based on the pressure deviation range of the pressure, select the corresponding pressure correction coefficient, multiply the initial compression ratio by the corresponding pressure correction coefficient, and obtain the pressure-corrected compression ratio.

[0050] The preset pressure reference value is the ideal reference parameter for the inlet pressure of the multiphase compressor. It refers to the standard inlet pressure value that enables the unit to maintain optimal compression efficiency and stable operation under design conditions. It is determined based on the design parameters of the multiphase compressor and the optimal operating pressure range corresponding to the target gas-liquid ratio. Specifically, it refers to the recommended inlet pressure corresponding to the gas-liquid ratio range that matches the preset compression characteristic rules in the unit's factory performance curve.

[0051] By combining historical inlet pressure data during normal gas well production, the midpoint of the intersection of the two data points is taken as the preset pressure benchmark value to ensure that it is within the pressure range for efficient operation of the equipment.

[0052] Based on the deviation between the temperature and the preset temperature reference value, the compression ratio after pressure correction is temperature corrected to obtain the compression ratio after temperature correction.

[0053] It should be added that the temperature correction of the compression ratio after pressure correction includes: dividing the temperature deviation range according to the preset temperature reference value, including the high temperature deviation range, the normal deviation range and the low temperature deviation range.

[0054] A corresponding temperature correction factor is matched for each temperature deviation range. The high temperature deviation range corresponds to a correction factor greater than 1, the normal deviation range corresponds to a correction factor equal to 1, and the low temperature deviation range corresponds to a correction factor less than 1. When the temperature is too high, the compression ratio is reduced, and when the temperature is too low, the compression ratio is increased.

[0055] Based on the temperature deviation range of the temperature, a corresponding temperature correction coefficient is selected, and the compression ratio after pressure correction is multiplied by the temperature correction coefficient to obtain the compression ratio after temperature correction.

[0056] The preset temperature reference value is the ideal reference parameter for the inlet temperature of the multiphase compressor, referring to the standard inlet temperature value that matches the compression performance of the device under design conditions. The preset temperature reference value is determined based on the physical properties of the multiphase flow medium and the temperature tolerance range of the device. Specifically, it involves determining the temperature range of the stable multiphase flow state at the target gas-liquid ratio based on experimental data, referencing the inlet temperature range allowed by the device design, and taking the midpoint of the intersection of these two ranges as the preset temperature reference value.

[0057] If the temperature-corrected compression ratio is within the allowable range of the multiphase compression device, then the compression ratio is taken as the optimal compression ratio. Otherwise, the corresponding boundary value is taken as the optimal compression ratio according to the direction of exceeding the limit. That is, if it is higher than the upper limit of the allowable range, the upper limit value is taken as the optimal compression ratio. If it is lower than the lower limit of the allowable range, the lower limit value is taken as the optimal compression ratio.

[0058] The embodiments of the present invention ensure that the compression ratio is within the efficient operating range of the multiphase compression device by matching the initial compression ratio based on the gas-liquid ratio and dynamically correcting it in combination with real-time pressure and temperature deviations. This avoids over-compression caused by parameter fluctuations, significantly improves compression efficiency, and reduces energy consumption costs.

[0059] The flow pattern defoaming control module, after executing the optimal compression ratio, inputs the compressed multiphase flow into the separator and detects the flow pattern of the compressed multiphase flow in the inlet pipe. Based on the flow pattern and the preset flow pattern-defoamer correlation, it sets the initial injection rate of the defoamer and detects the foam rate in the separator. If it exceeds the preset range, it adjusts the injection rate.

[0060] It should be added that setting the initial injection rate of the defoamer includes: matching the flow pattern of the compressed multiphase flow with the flow pattern corresponding to each defoamer reference injection rate in the preset flow pattern-defoamer association relationship to obtain the defoamer reference injection rate.

[0061] The baseline injection rate is used as the initial injection rate of the defoamer.

[0062] The flow pattern-defoamer correlation is a comprehensive rule system that integrates the baseline injection rate and dynamic adjustment rules. Specifically, it includes two core components: the baseline injection rate of defoamer for each flow pattern: for typical flow patterns such as bubbly flow, slug flow, and annular flow, a baseline value for initial injection is set. Based on the differences in foam characteristics of the flow patterns, such as the fact that slug flow has a large and stable amount of foam due to intense gas-liquid mixing, its baseline rate is higher than that of bubbly flow. This baseline value is obtained from the lowest effective injection rate determined experimentally.

[0063] Injection rate adjustment rules for each flow pattern: For each flow pattern, a preset adjustment strategy is established when the foam rate deviates from the normal range. If the foam rate is higher than the normal range, the adjustment range is set according to the flow pattern characteristics. For example, slug flow has high foam stability, so a larger proportion of the injection rate needs to be increased. Annular flow foam is easier to control, and the adjustment range can be reduced.

[0064] If the foam rate is lower than the normal range, the reduction ratio should be set according to the flow pattern and the sensitivity of the agent. For example, if the bubbly flow is more sensitive to excessive agent, the rate should be reduced more significantly to avoid agent waste.

[0065] The method for establishing the correlation is as follows: The foam generation and defoaming processes under different flow patterns are simulated experimentally. First, the foam volume, stability, and other characteristics of each flow pattern are measured to determine the corresponding baseline injection rate. Then, operating conditions with high / low foam ratios are simulated to test the impact of different adjustment ranges on the defoaming effect, summarizing the adjustment rules specific to each flow pattern. Finally, the baseline rate and adjustment rules are integrated into a flow pattern-defoamer correlation.

[0066] For example, the detection of the flow pattern of the compressed multiphase flow in the inlet pipe includes: installing a high-frequency pressure sensor, a capacitive phase content sensor and a high-speed camera in the straight section of the separator inlet pipe to simultaneously collect fluid pressure fluctuation signals, gas phase ratio distribution of the pipe cross section and dynamic images of the flow pattern.

[0067] The collected pressure fluctuation signals are processed to extract the pressure fluctuation amplitude between adjacent measuring points.

[0068] The average gas phase ratio distribution of the pipeline cross section is calculated to obtain the average gas phase ratio, and the gas-liquid interface morphology features are extracted from the dynamic flow pattern image.

[0069] The pressure fluctuation amplitude, average gas phase ratio, and gas-liquid interface morphology characteristics are matched with the parameter ranges corresponding to each flow pattern.

[0070] It should be added that if the pressure fluctuation amplitude, average gas phase ratio, and gas-liquid interface morphology characteristics correspond to different flow patterns, the gas-liquid interface morphology characteristics shall be the core criterion for judgment. The parameter ranges corresponding to each flow pattern are obtained based on statistical verification of experimental data. The specific steps are as follows: Different flow patterns are simulated in the laboratory, and a large number of samples are simultaneously recorded using a high-frequency pressure sensor, a capacitive phase content sensor, and a high-speed camera to measure the pressure fluctuation amplitude, average gas phase ratio, and interface morphology characteristics.

[0071] Statistical analysis was performed on the collected sample data to determine the concentrated distribution range of parameters under each flow pattern. The pressure fluctuation range in which more than 90% of the samples fall was taken as the pressure interval of that flow pattern.

[0072] The mean intervals were divided based on the clustering results of the average gas phase proportion. At the same time, the interface morphology features were classified by image recognition to extract typical morphological descriptions of each flow pattern, such as bubble diameter and interface adhesion.

[0073] The flow pattern of the compressed multiphase flow is determined based on the matching results. The flow patterns include bubbly flow, slug flow, and annular flow.

[0074] For example, adjusting the injection rate includes comparing the foam rate in the separator with a preset range to determine its range.

[0075] It should be noted that the preset range refers to the normal fluctuation range of the foam rate within the separator, that is, the foam rate threshold range that ensures gas-liquid separation efficiency and does not affect subsequent processing. When the foam rate is within this range, there is no need to adjust the defoamer injection rate. When it exceeds the range, the injection rate needs to be adjusted accordingly to maintain stable separation.

[0076] The steps for setting the preset range are as follows: By experimentally testing the gas-liquid separation effect under different foam ratios, the foam ratio range that can make the separation efficiency greater than 95% is determined as the initial reference range.

[0077] By simulating fluctuations in operating conditions such as gas-liquid ratio and pressure, the separation stability at the boundary of the test range is tested. The ranges in which the separation index exceeds the standard due to fluctuations in operating conditions are eliminated, and the final determined range is the preset range.

[0078] If the foaming rate is in a high range, the injection rate of the defoamer is increased based on the injection rate adjustment rule of the corresponding flow pattern in the flow pattern-defoamer correlation.

[0079] If the foaming rate is in a low range, the injection rate of the defoamer is reduced based on the injection rate adjustment rule of the corresponding flow pattern in the aforementioned correlation.

[0080] If the foaming rate is within the normal range, keep the defoamer injection rate constant.

[0081] This invention solves the problem that a single injection strategy is difficult to adapt to complex flow patterns by setting the initial injection rate of the defoamer based on the flow pattern and adjusting it in real time according to the foam rate in the separator. At the same time, it avoids gas-liquid entrainment caused by excessive or insufficient foam, and effectively improves the purity of gas-liquid separation.

[0082] The gas-liquid separation control module detects the gas-liquid ratio, foam rate, liquid flow rate, gas pressure, and real-time liquid level in the separator, calculates the required gas and liquid volumes for separation, determines the gas outlet pressure setpoint and the liquid outlet control valve opening based on this, and executes the corresponding control.

[0083] For example, the calculation of the required gas phase volume for separation includes: determining the proportion of the gas phase in the total effective volume of the separator based on the gas-liquid ratio in the separator, wherein the proportion is positively correlated with the gas-liquid ratio, and the higher the gas-liquid ratio, the greater the proportion of the gas phase.

[0084] The product of the total effective volume of the separator and the proportion of the gas phase is used as the theoretically required volume for the gas phase.

[0085] The foam ratio in the separator is matched with the foam ratio range corresponding to each volume ratio correction coefficient to obtain the volume ratio correction coefficient.

[0086] It should be added that the foam rate range corresponding to each volume ratio correction coefficient refers to dividing the possible foam rate within the separator into several continuous or discrete numerical ranges, with each range corresponding to a preset volume ratio correction coefficient. The higher the foam rate, the smaller the correction coefficient, in order to compensate for the loss of effective gas phase volume caused by foam crowding out space.

[0087] The method for determining the foam rate intervals corresponding to each volume ratio correction coefficient is as follows: by simulating the gas-liquid separation process under different foam states through experiments, the correlation between foam quantity and effective gas phase space is analyzed, and the foam rate is divided into corresponding characteristic intervals according to the degree of foam encroachment on the gas phase space.

[0088] For each interval, a corresponding volume ratio correction coefficient is set based on the actual effect of foam crowding out the gas phase space to compensate for the deviation of foam from the theoretical gas phase volume. At the same time, the correction coefficient must meet the reasonable distribution constraints of the total effective volume of the separator to ensure that the corrected gas phase volume does not exceed the space range allowed for safe operation of the equipment, thereby obtaining the foam rate interval corresponding to each volume ratio correction coefficient.

[0089] The product of the volume ratio correction factor and the volume required by the gas phase theory is used as the gas phase volume required for separation.

[0090] For example, the calculation of the required liquid volume for separation includes: determining the proportion of liquid phase in the total effective volume of the separator based on the gas-liquid ratio in the separator.

[0091] Based on the total effective volume of the separator, calculate the theoretical volume required for the liquid phase, where the theoretical volume required for the liquid phase is the product of the total effective volume and the proportion of liquid phase.

[0092] Based on the liquid flow rate and the theoretically required volume of the liquid phase, the actual residence time of the liquid phase in the separator is calculated, where the actual residence time is the calculated result of dividing the theoretically required volume of the liquid phase by the liquid flow rate.

[0093] The actual residence time is compared with the preset residence time. If the actual residence time is greater than or equal to the preset residence time, the theoretically required volume of the liquid phase is used as the required volume of the liquid phase for separation.

[0094] If the actual stay time is less than the preset stay time, the difference between the preset stay time and the actual stay time will be used as the time difference.

[0095] The ratio of the time difference to the preset residence time is used as the time correction coefficient. This coefficient is then multiplied by the theoretically required volume of the liquid phase. The sum of the product and the theoretically required volume of the liquid phase is used as the required liquid phase volume for separation.

[0096] For example, determining the gas phase outlet pressure setpoint includes: matching the required gas phase volume for separation with the gas phase volume range corresponding to each initial gas phase pressure value to obtain the initial gas phase pressure value.

[0097] It should be added that the gas phase volume range corresponding to each initial gas phase pressure value refers to the gas phase volume range that is defined for each different initial gas phase pressure value. Each initial gas phase pressure value corresponds to a specific range, and the gas phase volume within the range can be stably maintained by that initial pressure value.

[0098] The gas phase volume range corresponding to each initial gas phase pressure value is obtained based on the pressure-volume characteristic experiment of the separator medium. The specific process is as follows: through simulation experiment, the volume change law of the medium in the separator under different pressures is determined, the gas phase outlet pressure is gradually adjusted, and the actual volume occupied by the gas phase under the corresponding pressure is recorded.

[0099] Plot the pressure-volume relationship curve, observe the curve trend, and divide the interval according to the logic of pressure value → corresponding volume range based on the curve characteristics. Select several typical pressure values ​​as the initial values ​​of gas phase pressure, and for each initial value, determine the volume range that it can stably maintain, thereby obtaining the gas phase volume range corresponding to the initial value of gas phase pressure.

[0100] The gas phase pressure is compared with the initial value of the gas phase pressure. If the gas phase pressure is higher than the initial value, the relative deviation of the gas phase pressure is calculated. The product of the relative deviation and the initial value is taken as the reduction range. The difference between the gas phase pressure and the reduction range is taken as the set value of the gas phase outlet pressure.

[0101] The relative deviation of gas phase pressure is calculated as follows: the difference between the gas phase pressure and the initial value of the gas phase pressure is taken as the ratio of the difference to the initial value of the gas phase pressure.

[0102] If the gas phase pressure is lower than the set value, calculate the relative deviation of the gas phase pressure, use the product of the relative deviation and the initial value as the increase, and use the sum of the gas phase pressure and the increase as the set value of the gas phase outlet pressure.

[0103] If the gas phase pressure is equal to the initial value, the gas phase pressure will be used as the set value for the gas phase outlet pressure.

[0104] In this embodiment of the invention, the theoretical volumes of the gas and liquid phases are calculated by the gas-liquid ratio and corrected by combining the foam rate and liquid phase residence time. This ensures that the gas and liquid phase volume distribution matches the real-time operating conditions. At the same time, the gas phase outlet pressure setpoint and the liquid phase outlet control valve opening are dynamically adjusted to maintain the gas-liquid balance in the separator.

[0105] Please see Figure 3 As shown, exemplarily, determining the opening degree of the liquid phase outlet control valve includes: using the ratio of the liquid phase volume to the cross-sectional area of ​​the separator as the target liquid level at the liquid phase outlet.

[0106] Compare the real-time liquid level in the separator with the target liquid level. If the real-time liquid level is higher than the target liquid level, increase the opening of the liquid phase outlet control valve. The opening increases with the magnitude of the liquid level exceeding the target level.

[0107] It should be added that the specific steps for increasing the opening of the liquid phase outlet control valve are as follows: calculate the relative deviation between the real-time liquid level and the target liquid level to obtain the liquid level deviation ratio.

[0108] The product of the current opening degree of the liquid outlet control valve and the liquid level deviation ratio is used as the opening adjustment range. The sum of this product and the current opening degree is used as the theoretical adjustment opening degree of the liquid outlet control valve. At the same time, the theoretical adjustment opening degree is compared with the maximum opening degree of the liquid outlet control valve. If the theoretical adjustment opening degree is greater than the maximum opening degree of the liquid outlet control valve, the maximum opening degree of the liquid outlet control valve is used as the opening degree of the liquid outlet control valve. Otherwise, the theoretical adjustment opening degree is used as the opening degree of the liquid outlet control valve.

[0109] If the real-time liquid level is lower than the target liquid level, reduce the opening of the liquid phase outlet control valve, wherein the opening decreases as the liquid level falls below the target level.

[0110] It should be added that the specific steps for reducing the opening of the liquid phase outlet control valve are as follows: calculate the relative deviation between the real-time liquid level and the target liquid level to obtain the liquid level deviation ratio.

[0111] The product of the current opening degree of the liquid phase outlet control valve and the liquid level deviation ratio is used as the opening adjustment range, and the difference between the current opening degree and the deviation ratio is used as the opening degree of the liquid phase outlet control valve.

[0112] If the real-time liquid level is within the allowable fluctuation range of the target liquid level, the current opening degree remains unchanged, thereby obtaining the opening degree of the liquid phase outlet control valve.

[0113] This invention provides a closed-loop control system through parameter linkage. The results of abnormal handling affect subsequent compression parameters, flow pattern data guides defoaming strategies, and demand feedback supports pressure and opening control, thereby reducing manual intervention. At the same time, the precise location and individual handling of abnormal wellheads avoids system-wide shutdown for troubleshooting, significantly shortens fault response time, and improves overall production continuity.

[0114] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented using software, the above embodiments can be implemented, in whole or in part, in the form of a computer program product.

[0115] Those skilled in the art will recognize that the modules and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0116] In addition, the functional modules in the various embodiments of this application can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module.

[0117] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.

[0118] Finally, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A gas well multiphase flow gas liquid separation intelligent control system, characterized in that: The method comprises the following steps: A sand removal standard judgment module is used to input the gas after sand removal of each wellhead into a collection header, detect the sand content, and determine whether the sand removal is up to standard; An abnormal wellhead positioning module is used to detect the sand content of the output pipeline of each wellhead if the sand removal is not up to standard, calculate the abnormal contribution degree in combination with the flow rates of the wellhead and the header, and position the abnormal wellhead; The positioning of the abnormal wellhead comprises the following steps: the sand content of each wellhead output pipeline and the collection header is multiplied by the flow rate respectively to obtain the sand contribution value of each wellhead and the collection header respectively; the sand contribution values of each wellhead and the collection header are subjected to ratio calculation to obtain the abnormal contribution degree of each wellhead; the abnormal contribution degrees of each wellhead are compared with a preset abnormal contribution degree threshold value, and the wellhead with an abnormal contribution degree greater than the preset abnormal contribution degree threshold value is screened as the abnormal wellhead; An abnormal treatment closed loop module is used to close the output pipeline of the abnormal wellhead, start secondary sand removal of the wellhead, and verify until the sand removal is up to standard, and then restart the output pipeline; A compression ratio optimization module is used to input the gas up to standard into a multiphase compression device, detect the pressure, gas-liquid ratio, and temperature of the multiphase flow in the device, and determine the optimal compression ratio in combination with a preset compression characteristic rule; The setting process of the preset compression characteristic rule comprises the following steps: for the multiphase compression device, the operating parameters under different compression ratios and the gas-liquid ratio range under the corresponding working conditions are tested through experiments; according to the test data, the gas-liquid ratio is divided into a plurality of continuous intervals, and each interval is matched with a compression ratio; the above intervals are subjected to boundary correction in combination with the design parameters of the device to ensure that the compression ratios involved in the rule do not exceed the safe operation range of the device; the corresponding relationship between the divided gas-liquid ratio intervals and the compression ratios is solidified as the preset compression characteristic rule, which is used as a reference for matching the initial compression ratio subsequently; A flow pattern and defoaming agent injection rate control module is used to input the compressed multiphase flow into a separator after the optimal compression ratio is executed, detect the flow pattern of the compressed multiphase flow in the inlet pipeline, set the initial injection rate of the defoaming agent based on the flow pattern and a preset flow pattern-defoaming agent correlation, and detect the foam rate in the separator; if the foam rate exceeds a preset range, the injection rate is adjusted; The flow pattern-defoaming agent correlation comprises two core contents: the defoaming agent reference injection rate corresponding to each flow pattern; for bubbly flow, slug flow, and annular flow, the reference values of the initial injection are set respectively, and the reference value of the slug flow is higher than that of the bubbly flow based on the difference in the foam characteristics of the flow patterns; the reference value is obtained from the lowest effective injection rate determined by experiments; A gas-liquid separation control module is used to detect the gas-liquid ratio, foam rate, liquid phase flow rate, gas phase pressure, and real-time liquid level in the separator, calculate the gas phase volume and liquid phase volume required for separation, determine the gas phase outlet pressure set value and liquid phase outlet control valve opening degree based on the calculation results, and execute corresponding control.

2. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The determination of whether the sand removal is up to standard comprises the following steps: The sand content of the collection header is compared with a preset sand content critical value; If the sand content of the collection header is less than the preset sand content critical value, it is determined that the sand removal is up to standard, otherwise, it is determined that the sand removal is not up to standard.

3. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The determination of the optimal compression ratio comprises the following steps: The gas-liquid ratio of the multiphase flow is matched with the gas-liquid ratio interval corresponding to each compression ratio in the preset compression characteristic rule to obtain the initial compression ratio of the multiphase flow; The initial compression ratio is pressure-corrected based on the deviation of the pressure from a preset pressure reference value, to obtain a pressure-corrected compression ratio; The pressure-corrected compression ratio is temperature-corrected based on the deviation of the temperature from a preset temperature reference value, to obtain a temperature-corrected compression ratio; If the temperature-corrected compression ratio is within the compression ratio allowable range of the multiphase compression device, the compression ratio is taken as the optimal compression ratio, otherwise, a corresponding boundary value is taken as the optimal compression ratio according to the overrun direction.

4. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The detection of the flow pattern of the compressed multiphase flow in the inlet pipeline comprises: A high-frequency pressure sensor, a capacitive phase content rate sensor and a high-speed camera are installed on the straight pipe section of the separator inlet pipeline to synchronously collect fluid pressure fluctuation signals, pipeline cross-section gas phase proportion distribution and flow pattern dynamic images; The collected pressure fluctuation signals are processed to extract pressure fluctuation amplitudes between adjacent measuring points; The pipeline cross-section gas phase proportion distribution is subjected to mean value calculation to obtain a gas phase proportion mean value, and a gas-liquid interface shape feature is extracted from the flow pattern dynamic image; The pressure fluctuation amplitude, the gas phase proportion mean value and the gas-liquid interface shape feature are respectively matched with parameter intervals corresponding to each flow pattern; The flow pattern of the compressed multiphase flow is determined according to the matching result, and the flow pattern comprises bubbly flow, slug flow and annular flow.

5. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The adjustment of the injection rate comprises: The foam rate in the separator is compared with a preset range to determine the interval in which it is located; If the foam rate is in a high interval, the injection rate of the defoaming agent is increased based on the injection rate adjustment rule of the corresponding flow pattern in the flow pattern-defoaming agent correlation relationship; If the foam rate is in a low interval, the injection rate of the defoaming agent is decreased based on the injection rate adjustment rule of the corresponding flow pattern in the correlation relationship; If the foam rate is in a normal interval, the injection rate of the defoaming agent is kept unchanged.

6. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The calculation of the required gas phase volume for separation comprises: The gas phase proportion of the gas phase in the total effective volume in the separator is determined according to the gas-liquid ratio in the separator; The product of the total effective volume and the gas phase proportion is calculated as the theoretical required volume of the gas phase in combination with the total effective volume of the separator; The foam rate in the separator is matched with the foam rate interval corresponding to each volume proportion correction coefficient to obtain the volume proportion correction coefficient; The product of the volume proportion correction coefficient and the theoretical required volume of the gas phase is calculated as the required gas phase volume for separation.

7. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The calculation of the required liquid phase volume for separation comprises: The liquid phase proportion of the liquid phase in the total effective volume in the separator is determined according to the gas-liquid ratio in the separator; The theoretical required volume of the liquid phase is calculated in combination with the total effective volume of the separator; The actual residence time of the liquid phase in the separator is calculated based on the liquid phase flow rate in combination with the theoretical required volume of the liquid phase; The actual residence time is compared with a preset residence time, and if the actual residence time is greater than or equal to the preset residence time, the theoretical required volume of the liquid phase is taken as the required liquid phase volume for separation; If the actual residence time is less than the preset residence time, a time difference value is obtained by subtracting the actual residence time from the preset residence time; A time correction coefficient is obtained by dividing the time difference value by the preset residence time, and then the time correction coefficient is multiplied by the theoretical required volume of the liquid phase, and the sum of the product calculation result and the theoretical required volume of the liquid phase is taken as the required liquid phase volume for separation.

8. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The determining of the gas phase outlet pressure set value comprises: matching the separated gas phase volume with the gas phase volume interval corresponding to each gas phase pressure initial value to obtain the gas phase pressure initial value; comparing the gas phase pressure with the gas phase pressure initial value, if the gas phase pressure is higher than the initial value, calculating the relative deviation degree of the gas phase pressure, taking the product of the relative deviation degree and the initial value as the reduction amplitude, and taking the difference between the gas phase pressure and the reduction amplitude as the gas phase outlet pressure set value; if the gas phase pressure is lower than the initial value, calculating the relative deviation degree of the gas phase pressure, taking the product of the relative deviation degree and the initial value as the increase amplitude, and taking the sum of the gas phase pressure and the increase amplitude as the gas phase outlet pressure set value; if the gas phase pressure is equal to the initial value, taking the gas phase pressure as the gas phase outlet pressure set value.

9. The intelligent control system for gas well multiphase flow liquid separation according to claim 1, characterized in that: The determining of the liquid phase outlet control valve opening degree comprises: taking the ratio of the liquid phase volume and the cross-sectional area of the separator as the target liquid level of the liquid phase outlet; comparing the real-time liquid level in the separator with the target liquid level, if the real-time liquid level is higher than the target liquid level, increasing the liquid phase outlet control valve opening degree; if the real-time liquid level is lower than the target liquid level, decreasing the liquid phase outlet control valve opening degree; if the real-time liquid level is within the allowable fluctuation range of the target liquid level, keeping the current opening degree unchanged, and then obtaining the liquid phase outlet control valve opening degree.

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