A device for measuring the amount of crude oil in a pipeline

Abstract

This invention relates to a pipeline crude oil volume detection device, comprising a dual-branch pipeline, a flow velocity detection module, a water content detection module, a liquid level detection module, and a control and data processing system. The dual-branch pipeline divides from a main pipeline into two identical branches. The flow velocity detection module measures the flow velocity of the liquid within the pipeline, the water content detection module measures the water content of the liquid phase, and the liquid level detection module measures the liquid level height to calculate the specific gravity and gas content of the liquid. Data collected by sensors in the flow velocity, water content, and liquid level detection modules is sent to the control and data processing system for data processing to obtain the flow velocity, liquid level height, three-phase flow volume ratio, and flow rate. This detection device is used for detecting near-laminar three-phase flow in production and transportation pipelines, capable of measuring flow velocity, liquid level height, phase ratio, and liquid flow rate. This device employs a non-separation method, non-contact detection, is easy to disassemble, and produces no radiation pollution, showing broad application prospects.

Description

Technical Field

[0001] The invention belongs to the technical field of petroleum equipment, and in particular relates to a pipeline crude oil liquid quantity measuring device, which is suitable for oil, water and gas three-phase flow production and transportation pipelines. Background Art

[0002] With the continuous exploitation of oil, the pressure of oil wells is constantly decreasing with the exploitation of crude oil. At present, water injection and pressurization are more often used for oil production. Water injection in oil wells causes the widespread existence of oil, gas and water phases in oil wells, as well as high water content caused by long-term water injection. Therefore, in order to reduce the cost of oil production and formulate a reasonable production plan, it is necessary to accurately measure the flow rate of each phase of the three phases. At present, the main measurement methods are: capacitance method, conductivity method, ray method and microwave method, etc. Among them, the conductivity method uses the difference in conductivity between oil and water to measure the water content. It has low cost and simple structure and is only used for low water content measurement. The ray method calculates the water content based on the different absorption rate of liquid to ray. This method has a wide measurement range, but there is radiation. The microwave method uses different proportions of oil and water mixtures to measure different microwave absorption. This method has high accuracy, but is easily affected by the environment. The capacitance method is a non-contact measurement. Due to the different dielectric constants of oil and water in different proportions, the measured capacitance values ​​are different, and the water content is obtained.

[0003] Depending on whether the three phases are separated before measurement, multiphase flow meters can be divided into two categories: separation type and non-separation type. Separation type: The three-phase mixed liquid is separated into three single-phase flows through a separator, and then the flow rate of each phase is measured separately. This method is easy to measure, has high accuracy, and a wide measurement range. However, due to the separator, this multiphase flow meter occupies a large area, is expensive, and is difficult to achieve real-time online measurement. It is not suitable for flow types where oil and water are not easy to separate. Non-separation measurement: The three-phase flow is directly measured without any separation. Compared with the separation measurement method, this flow meter has the advantages of small size, low cost, and easy installation. It does not require a lot of cost to maintain and clean it, and can be installed at any position on the oil well production line to achieve real-time online measurement.

[0004] In 2007, Ma Min and others from Tianjin University used the gamma-ray method to detect three-phase flow, using five ray sources for surround detection of the three-phase flow. This method has accurate measurement results, but the structure is complex, the cost is high, and there is radiation to the outside. In 2022, Ma Ruixiang and others from Jilin University used the capacitance method to detect three-phase flow, combined with a differential pressure sensor to measure the liquid level to determine the proportion of the three-phase flow. This method has a simple structure, uses a non-separation structure, and has accurate results, but because the differential pressure sensor can only withstand limited pressure, it can only be used for measurements in low-pressure and low-flow environments. Summary of the invention

[0005] The purpose of the present invention is to provide a non-separation structure, low cost, simple structure, intelligent crude oil pipeline three-phase flow online detection device, which adopts non-contact measurement, is safe, convenient and radiation-free, so as to solve the problem of effectively evaluating the three-phase flow in the pipeline under the state of low-speed near-laminar flow, and provide a reliable basis for the state of crude oil during extraction and transportation.

[0006] The objective of the present invention is achieved through the following technical solutions:

[0007] A pipeline crude oil liquid volume measuring device comprises a double-branch pipeline 1, a flow rate detection module 2, a water content detection module 3, a liquid level detection module 4 and a control and data processing system 5;

[0008] The double-branch pipeline 1 is divided into two identical branches from the main pipeline; the flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 are installed on any branch measuring pipeline of the double-branch pipeline 1; the flow rate detection module 2 is used to measure the flow rate of the liquid in the pipeline; the water content detection module 3 is used to measure the water content of the liquid phase; the liquid level detection module 4 can measure the liquid level height, which is used to calculate the liquid specific gravity and gas content, and its exhaust system 6 can discharge excess gas so that the air pressure in the sampling space is maintained at a standard atmospheric pressure during measurement; the sensors in the flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 collect data and send them to the control and data processing system 5 for data processing to obtain the flow rate, liquid level height, three-phase flow volume ratio and flow rate.

[0009] Furthermore, the double-branch pipeline 1 is a group of symmetrical cylindrical pipelines made of non-metal, which is connected to the main pipeline. The branching angle γ of the double-branch pipeline 1 is in the range of 5°-10°, and the cross-sectional area of ​​the branch circular pipeline is 1 / 2-1 times that of the main pipeline. An extended oil pipeline can be added to the front end of the main pipeline, and the length of the crude oil flowing into the measuring pipeline can be extended.

[0010] Furthermore, the flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 are all installed outside the pipeline. Starting from the branch part of the main pipeline, the flow rate detection module 2, the left electronic valve 22, the water content detection module 3, the barometer 19, the liquid level detection module 4, the exhaust valve 21, and the right electronic valve 23 are sequentially arranged on the measuring pipeline; the outer side of the right electronic valve 23 is the air intake valve 18, which is responsible for discharging excess gas in the measuring interval to the main pipeline.

[0011] Furthermore, the flow rate detection module 2 is composed of two groups of capacitors, two groups of capacitance sensors and two AD acquisition modules. The two groups of capacitance plates are made into rings and embedded in the outer wall of the pipeline. The two groups of capacitance sensors are placed at a distance L in the pipeline.

[0012] Furthermore, the distance between the left electronic valve 22 and the right electronic valve 23 is 0.5-5m, and the distance between the barometer 19 and the air extraction valve 21 is greater than 50cm.

[0013] Furthermore, the moisture content detection module 3 is composed of a capacitor, a capacitor sensor III 24, an AD acquisition module III 25 and a temperature sensor 26. The two capacitor plates are respectively embedded in the left and right sides of the measuring pipe, and are controlled and processed by the control and data processing system 5. The inlet and outlet sides of the measuring pipe are connected to the left electronic valve 22 and the right electronic valve 23. The top side of the measuring pipe is provided with a barometer 19 and a liquid level detection module 4.

[0014] Furthermore, the liquid level detection module 4 includes an air pumping system 6 and an ultrasonic sensor 15. The air pumping system 6 pumps the air pressure in the pipeline measurement area to one atmosphere when in operation, providing a standard working air pressure condition for the ultrasonic sensor 15. The ultrasonic sensor 15 measures the current liquid level.

[0015] Furthermore, the ultrasonic sensor 15 is installed in a conical cavity, the cavity height is greater than the ultrasonic sensor blind area, which is 5-20 cm, the cone angle of the conical cavity is between 10°-20°, and is connected to the liquid level detection module valve 20.

[0016] Furthermore, the ultrasonic sensor 15 is arranged above the measuring pipe and the distance from the measuring pipe is greater than 5 cm.

[0017] Furthermore, the control and data processing system 5 is a PC or an embedded control system, which can output logic instructions to control the opening and closing of each valve of the entire device; at the same time, it collects the information transmitted by the flow rate detection module 2, the moisture content detection module 3, and the liquid level detection module 4 in real time, analyzes and calculates the result information such as the specific gravity and flow rate of each component, and then transmits it to the user through the display device.

[0018] Compared with the prior art, the present invention has the following beneficial effects:

[0019] The pipeline crude oil liquid volume measuring device of the present invention realizes the real-time online non-destructive detection of the oil, water and gas content and flow rate under low-speed near-laminar flow by combining capacitance and ultrasonic wave. The device has the characteristics of small size, low cost, easy installation and strong applicability. The pipeline crude oil liquid volume measuring device of the present invention is economical, convenient and practical, and has strong universality. BRIEF DESCRIPTION OF THE DRAWINGS

[0020] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for use in the embodiments are briefly introduced below. It should be understood that the following drawings only show certain embodiments of the present invention and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other related drawings can be obtained based on these drawings without creative work.

[0021] Figure 1 Top view of the distribution of modules of the three-phase flow device;

[0022] Figure 2 Detailed top view of the three-phase flow device;

[0023] Figure 3 A side view of a liquid level detection module of a three-phase flow detection device;

[0024] Figure 4 Side view of a capacitive sensor;

[0025] Figure 5 Schematic diagram of data acquisition and processing of the overall device module;

[0026] Figure 6 Schematic diagram of the measurement cycle;

[0027] Figure 7 Relationship between capacitance and water content under different oil-water mixing models;

[0028] Figure 8 Relationship diagram between different gas, oil and water ratios and sensor values;

[0029] Fig. 9 A graph showing the relationship between the liquid level and the cross-sectional area of ​​a pipe;

[0030] Fig.10 Schematic diagram of three-phase near-laminar flow;

[0031] Fig.11 Curve of the relative dielectric constant of water changing with temperature.

[0032] In the figure, 1. double branch pipeline 2. flow rate detection module 3. water content detection module 4. liquid level detection module 5. control and data processing system 6. exhaust system 7. capacitance sensor Ⅰ 8. capacitance plate Ⅰ 9. capacitance plate Ⅱ 10. AD acquisition module Ⅰ 11. capacitance sensor Ⅱ 12. capacitance plate Ⅲ 13. capacitance plate Ⅳ 14. AD acquisition module Ⅱ 15. ultrasonic sensor 16. capacitance plate Ⅴ 17. capacitance plate Ⅵ 18. intake valve 19. barometer 20. liquid level detection module valve 21. exhaust valve 22. electronic valve left 23. electronic valve right 24. capacitance sensor Ⅲ 25. AD acquisition module Ⅲ 26. temperature sensor. DETAILED DESCRIPTION

[0033] The present invention will be further described below in conjunction with embodiments:

[0034] The present invention will be further described in detail below in conjunction with the accompanying drawings and embodiments. It is to be understood that the specific embodiments described herein are only used to explain the present invention, rather than to limit the present invention. It should also be noted that, for ease of description, only parts related to the present invention, rather than all structures, are shown in the accompanying drawings.

[0035] It should be noted that similar reference numerals and letters represent similar items in the following drawings, so once an item is defined in one drawing, it does not need to be further defined and explained in the subsequent drawings. At the same time, in the description of the present invention, the terms "first", "second", etc. are only used to distinguish the description and cannot be understood as indicating or implying relative importance.

[0036] The present invention uses ultrasonic sensing and electromagnetic measurement technology to develop a device for measuring the liquid flow rate of crude oil three-phase flow. Figure 1 As shown, the device is mainly composed of a double-branch pipeline 1, a flow rate detection module 2, a water content detection module 3, a liquid level detection module 4, and a control and data processing system 5. Among them, the double-branch pipeline 1 is divided into two identical branches from the main pipeline. The flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 are installed on any branch measurement pipeline of the double-branch pipeline 1. The flow rate detection module 2 is used to measure the flow rate of the liquid in the pipeline. The water content detection module 3 is used to measure the water content of the liquid phase. The liquid level detection module 4 can measure the liquid level height, which is used to calculate the liquid specific gravity and gas content. The exhaust system 6 in the liquid level detection module 4 can discharge excess gas so that the air pressure in the sampling space is maintained at a standard atmospheric pressure during measurement, providing standard working conditions for the liquid level detection module 4. The sensor data collection results of the above-mentioned flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 are transmitted to the control and data processing system 5 for data processing to obtain the final flow rate, liquid level height, three-phase flow volume ratio and flow rate.

[0037] Double branch pipeline principle:

[0038] Double branch pipeline 1 Figure 1As shown, the flow rate detection module 2, the water content detection module 3 and the liquid level detection module 4 are all installed outside the pipeline, which will not affect the fluid. Starting from the branch part of the main pipeline, the flow rate detection module 2 is the first on the measuring pipeline, which includes two groups of sensors, and the two groups of sensors occupy a total of about 50cm of the pipeline. Then, the electronic valve left 22 and the electronic valve right 23, the spacing between them is about 0.5-5m, which are responsible for closing this section of the pipeline during measurement and performing static sampling measurement. In between are the water content detection module 3, the barometer 19, the liquid level detection module 4 and the air extraction valve 21. The distance between the barometer 19 and the air extraction valve 21 is greater than 50cm to avoid being affected by the Bernoulli principle, resulting in inaccurate air pressure measurement. The outside of the electronic valve right 23 is the air intake valve 18, which is responsible for discharging excess gas in the measurement interval to the main pipeline for special treatment. The double-branch pipeline 1 is a group of symmetrical cylindrical pipelines made of non-metal (preferably oleophobic material, such as resin material or inner wall sprayed with oleophobic coating), which is connected to the main pipeline. The branch angle γ of the double-branch pipeline 1 is in the range of 5°-10° to ensure that the impact of liquid flow diversion is small. The cross-sectional area of ​​the branch circular pipeline is 1 / 2-1 times that of the main pipeline. An extended oil pipeline can be added at the front end of the main pipeline to lengthen the length of the crude oil flowing into the measuring pipeline, making the three-phase flow smoother, facilitating stratification, and improving measurement accuracy.

[0039] Flow rate detection principle:

[0040] The flow rate detection module 2 is composed of two identical capacitors, a capacitor sensor I7, a capacitor sensor II11, an AD acquisition module I10 and an AD acquisition module II14. The capacitor plates of the two capacitors are capacitor plate I8, capacitor plate II9, capacitor plate III12 and capacitor plate IV13. Figure 2 As shown. Two identical capacitors and capacitance sensors Ⅰ7 and Ⅱ11 are placed at a distance L in the pipeline. The capacitor plates are made into a ring shape and embedded in the outer wall of the pipeline, as shown in FIG. Figure 4 The capacitance sensor is responsible for measuring the capacitance value between the two plates, and the AD acquisition module is responsible for converting the measured capacitance value into a digital value and uploading it to the control and data processing system 5. The capacitance sensor and the AD acquisition module can be integrated together.

[0041] The two sets of capacitor plates of the flow rate detection module 2 are mounted on the outer wall of the fluid pipeline in an inlaid manner, i.e., a so-called "clamp" structure (the "clamp" structure refers to the capacitor plates being made into an arc shape and embedded in the outer surface of the pipeline for fixing). The flow rate detection module 2 is controlled by the control and data processing system 5.

[0042] When the fluid flows, the electrostatic signals generated by the capacitive sensor in the corresponding area are x(t) and y(t). When the measured liquid flows steadily in the pipeline and the distance between the capacitive sensors is small enough, it can be approximately considered that the flow system satisfies the "solidification" hypothesis: the modulation effect caused by the transmission signal x(t) of the measured fluid at the upstream capacitive sensor I will repetitively appear at the downstream capacitive sensor II after a certain period of time (that is, the function shapes of x(t) and y(t) are almost the same), and a change similar to x(t) is generated but with a time lag of τ. The cross-correlation operation is performed to obtain the cross-correlation function:

[0043]

[0044] T is the integration time.

[0045] The cross-correlation function of the fluid with the "solidification" flow hypothesis property reaches its maximum value at τ. The peak value of the correlation function is retrieved, and the time corresponding to the peak value is the delay time. The relevant flow velocity is:

[0046] V 液 =L / τ

[0047] V 液 is the relevant flow velocity, indicating the flow velocity of the measured fluid (liquid phase oil and water); L is the distance between the two capacitance sensors. Here L is 5-20cm, and the flow velocity is 0.1m / s~4m / s. If the flow velocity is less than 0.1m / s, it can be treated as an empty pipe, that is, V 液 =0; it can also be processed according to a fixed low flow rate value according to the actual situation. The transit time does not exceed 0.5s.

[0048] Moisture content detection principle:

[0049] The moisture content detection module 3 is composed of a capacitor, a capacitor sensor III 24, an AD acquisition module III 25 and a temperature sensor 26; the capacitor has two plates, a capacitor plate V 16 and a capacitor plate VI 17, as shown in FIG. Figure 2 shown.

[0050] Specifically, the two capacitor plates of the water content detection module 3 are respectively embedded in the left and right sides of the measuring pipe, and are controlled and processed by the control and data processing system 5. The inlet and outlet sides of the measuring pipe are connected to the left electronic valve 22 and the right electronic valve 23, and the top side of the measuring pipe is provided with a barometer 19 and a liquid level detection module 4.

[0051] The principle of capacitance measurement is that due to the large difference in dielectric constants between oil and water, when the oil-water mixture flows through the middle of the electrode plate, the capacitance value changes due to the different dielectric constants of crude oil containing water in different proportions. When the size of the sensor is determined, the capacitance value is only proportional to the dielectric constant ε of the medium. The size of the capacitance is measured by the hardware measurement circuit, and the water content value can be obtained through data analysis and processing.

[0052] The capacitance value is only related to the dielectric constant of the medium:

[0053]

[0054] Θ is the half-opening angle of the arc gap, and the dielectric constant ε=ε r ε0,ε r is the relative dielectric constant; ε0 is the vacuum dielectric constant 8.85×10 -12 F / m. In the oil, water and gas three-phase near-laminar flow structure, the capacitance value C in the above formula can be regarded as the parallel connection of the three capacitors of oil, water and gas. The relationship between the output of the capacitance sensor and the different gas, water and oil ratios is as follows: Figure 8 As shown (the sum of the three phase proportions is 1). Since the relative dielectric constant of water is about 80, the relative dielectric constant of oil is about 2.6, and the relative dielectric constant of gas is 1; the dielectric constant of water is much larger than that of oil and gas, it can be seen that the output of the capacitive sensor mainly depends on the water content, such as Figure 8 As shown, the water content can be obtained according to the output of the capacitance sensor. The temperature sensor 26 integrated in the water content detection module 3 compensates for the dielectric constant of water. The temperature sensor 26 can be a platinum resistor, a thermocouple, an integrated temperature sensing element DS18B20, etc. According to the capacitance method, the dielectric constant of water in petroleum increases linearly with temperature, while the dielectric constants of the oil phase and the gas phase basically do not change with temperature. The specific relationship between the relative dielectric constant of water and temperature is shown in Fig.11 .

[0055] The fluid in the previous transport pipeline needs to flow straight for a long distance and time (the oil pipeline can be extended), and the liquid phase is almost stratified (from top to bottom, oil, oil-water, and water). Fig.10 shown.

[0056] However, due to the different states of oil-water mixing, the overall polarization is also uneven. It is necessary to analyze the various states of two-phase flow:

[0057] When the oil and water are in a laminar flow state, when a polarization electric field parallel to the surface of the two-phase flow medium is applied, the water phase and the oil phase medium are in a parallel state relative to the polarization field. This is also the main model based on which the present invention is measured. At this time, the dielectric constant is:

[0058] ε=mε w +(1-m)ε o

[0059] When a polarization electric field perpendicular to the surface is applied to the two-phase flow, the water and oil media are in series state relative to the polarization field, and the dielectric constant is:

[0060]

[0061] The exponential model is:

[0062]

[0063] The logarithmic model is:

[0064] lnε=mlnε w +(1-m)lnε o

[0065] ε represents the equivalent dielectric constant of the mixture; m represents the water content of the mixture; ε w Represents the relative dielectric constant of water; ε o Represents the relative dielectric constant of oil.

[0066] Maxwell model for the state of continuous and discrete phase mixture

[0067]

[0068] Among them, ε1 is the dielectric constant of the continuous phase, and ε2 is the dielectric constant of the discrete phase. This model requires that the discrete phase particles are small and the discrete phase is evenly dispersed in the continuous phase.

[0069] The Hanai model is:

[0070]

[0071] Among them, ε1 is the dielectric constant of the continuous phase, ε2 is the dielectric constant of the discrete phase, and α is the content of the discrete phase.

[0072] Since the capacitance value is proportional to the dielectric constant, a graph showing the relationship between capacitance value and water content can be drawn, such as Figure 7 As shown. Under the ideal quasi-static laminar flow state, according to the parallel model,

[0073] C 理论 =C 气 +C 油 +C 水

[0074] Among them, C 油 , C 水 , C 气 are the capacitance values ​​of the three phases of oil, water and gas under ideal laminar flow conditions. However, due to the disturbance of the fluid during actual flow, an oil-water mixed interface will appear between the water layer and the oil layer. On this interface, oil and water are fused together, namely:

[0075] C 理论 =C 气 +C′ 油 +C′ 水 +C 混

[0076] C′ 油 , C′ 水 , C 气 , C 混 are the capacitance values ​​of oil, water, gas and oil-water mixed layer under near laminar flow conditions.

[0077] C′ 油 +C′ 水 +C 混 =C 油 +C 水

[0078] according to Figure 7 It can be seen that in actual situations, it is not completely a parallel model, and there are other models. Therefore, the water content under the parallel model calculated by the capacitance value is slightly smaller than the actual water content. The capacitance value corresponding to the actual water content is:

[0079] C 实际 =C 气 +C′ 油 +C′ 水 +C 混 +ΔC

[0080] ΔC=ωC 理论

[0081] ΔC is much smaller than C 理论 , ω is much smaller than 1, so

[0082]

[0083] This ratio is an empirical value and can be measured by long-term accumulation on the production line. It is mainly determined by the flow rate. The larger the flow rate, the larger the value of ω, and the smaller the flow rate, the smaller the value of ω. When the calculation accuracy requirement is not high, ΔC can be ignored, that is, ω≈0.

[0084] Therefore, according to the actual measured capacitance value, the proportion of water phase in the three phases can be obtained: i , and then the liquid level height and equivalent area of ​​the water phase are obtained.

[0085] Liquid level detection principle:

[0086] like Figure 3 As shown, the liquid level detection module 4 includes an exhaust system 6 and an ultrasonic sensor 15. The ultrasonic sensor 15 emits ultrasonic waves toward the bottom of the pipe, and starts timing at the same time as the emission. The ultrasonic waves propagate in the air and immediately return when they hit the liquid surface. The ultrasonic receiver stops timing immediately when it receives the reflected wave. The distance from the emission position to the liquid surface can be estimated based on the time difference and the speed of the ultrasonic wave, and then the current liquid level height can be calculated. The interface of the three-phase near-laminar flow model is shown in FIG. Fig.10 shown.

[0087] Since the ultrasonic sensor 15 has high requirements for the air pressure of the working environment, before measurement, first close the left electronic valve 22 and the right electronic valve 23 of the pipeline, open the outlet valve 21 and the inlet valve 18, and use the exhaust system 6 to discharge the excess gas to the outside of the measurement area (the area behind the valve 23). When the barometer 19 determines that the air pressure is stable at 1 atmosphere (providing standard working air pressure conditions for the ultrasonic sensor 15), close the valve 21 and the exhaust system 6, open the liquid level detection module valve 20, and turn on the liquid level measurement module 4 to measure the liquid level.

[0088] The ultrasonic sensor 15 is installed in the conical cavity. Figure 3 As shown, the cavity height is greater than the blind area of ​​the ultrasonic sensor, which is 5-20 cm, and the cone angle of the conical cavity is between 10° and 20°. Specifically, the ultrasonic sensor 15 is placed above the pipeline, with a distance of more than 5 cm from the measuring pipeline, so that it detects outside the blind area and minimizes the height, and the output result is transmitted to the control and data processing system 5.

[0089] The overall structure measurement principle is as follows:

[0090] like Figure 5 As shown in Figure 1, when the liquid flows, it flows from the main pipe through the two branches. First, the flow rate detection module 2 measures and calculates the current flow rate V 液 ; Then close the left electronic valve 22 and the right electronic valve 23, open the air extraction valve 21 and the air inlet valve 18, connect the air extraction system 6, because the liquid level detection module 4 needs to ensure the working air pressure environment, use the air pump to control the internal air pressure at one atmosphere, and close the air extraction valve 21 and the air inlet valve 18. Open the valve 20 of the liquid level detection module, use the ultrasonic sensor 15 in the liquid level detection module 4 to measure the distance from the liquid surface to the upper part of the tube, and then calculate the height H of the liquid surface from the bottom, that is, the liquid phase height, such as Fig.10 As shown, the cross-sectional area of ​​the pipeline liquid phase can be calculated:

[0091]

[0092] Where r is the inner radius of the tube, and the calculation results are as follows Fig. 9 As shown, the cross-sectional area of ​​the gas is calculated;

[0093] S g =S 管 -S l

[0094] The gas volume ratio is thus At the same time, the capacitance measurement results of the moisture content detection module 3 are used in combination with Figure 8 Output and parameter relationship to determine the volume proportion of water α i , the volume proportion of oil is α j.

[0095] The above principle can be summarized as follows: first measure the liquid phase height, then Fig. 9 It can be seen that the liquid phase height and the cross section have a one-to-one correspondence, and then the cross-sectional area of ​​the liquid phase is obtained, and then the cross-sectional area of ​​the gas phase is calculated to obtain the gas volume proportion α g The volume ratio of water phase in the liquid phase is measured by the water content detection module 3 to obtain the capacitance value. Figure 8 The relationship between the capacitance sensor output and the water-gas ratio can be used to obtain the water phase ratio α i ; Among them, α i +α j +α g =1, so the oil phase accounts for α j Also sure.

[0096] After measurement, the proportion of three-phase flow has been determined. At this time, the electronic valve is opened. The flow rate detection module 2 continues to measure the real-time flow rate, and the water content measurement module 3 and the liquid level measurement module 4 are closed. According to the proportion of three-phase flow obtained during t1, the flow rate during the dual-channel working time is calculated.

[0097] Q 水1 =V 液 ×S 管1 ×α i

[0098] Q 油1 =V 液 ×S 管1 ×α j

[0099] V 液 It is measured by the flow rate detection module, representing the average flow rate of liquid (oil, water). The average flow rate of gas V g Due to the influence of the flow rate of the liquid and the gas pressure P in the tube, that is:

[0100] V g =V g (V 液 ,P)

[0101] V g It increases with the increase of liquid phase flow rate and pressure. The specific functional relationship is determined according to the actual situation. In rough calculation, it can be approximately assumed that the gas and liquid flow rates are equal. g ≈V 液 ,so,

[0102] Q 气1 =V g ×S g

[0103] Among them, Q 水1 for Figure 1The flow rate of water in pipe A, Q 油1 for Figure 1 The oil flow rate of pipeline A, Q 气1 for Figure 1 The gas flow rate of pipeline A, V 液 is the liquid flow rate, V g is the gas flow rate, and P is the pressure displayed by the barometer.

[0104] Ideally, the two branch pipes of the double-branch pipe 1, pipe A and pipe B, are symmetrical and placed horizontally, and the three-phase flow in the pipes should be the same. However, due to the influence of the earth's rotation, the liquid is affected by the Coriolis force during the flow process, the slight asymmetry of the double-branch pipe 1 during production, and the fluctuation of the pressure difference in the two pipes during operation, the actual liquid flow values ​​of the two pipes are not exactly the same. For example, the Coriolis force is perpendicular to the pipe wall, so Figure 1 The flow rate of pipe B in the top view is slightly larger than that of the pipe above. So let:

[0105] Q 水2 =βQ 水1

[0106] Q 油2 =βQ 油1

[0107] Because S g2 =S 管 -βS l ,so,

[0108] Q 气2 =V g ×S g2

[0109] β is an empirical value, close to 1, and is calibrated by actual measurement. In summary, in one cycle, the volume of the three-phase flow is

[0110]

[0111]

[0112]

[0113] Among them, Q 水2 for Figure 1 The flow rate of water in pipe B, Q 油2 for Figure 1 The oil flow rate of pipeline B, Q 气2 for Figure 1 The flow rate of gas in pipeline B, W 水 is the total volume of water in one cycle, W 油 is the total volume of oil in one cycle, W 气 is the total volume of gas in one cycle. Figure 6 As shown in the figure, t1 is the measurement time, ranging from 3s to 1min, and t2 is the dual-channel working time. T2 is set according to the actual working accuracy and total amount, ranging from 1 minute to several hours. The measurement period T = t1 + t2, requiring t1 < t2. Within t1, the device completes the valve closing sampling and the measurement of all data; the proportion of each measurement represents the liquid flow state of the dual pipes within the entire measurement period T.

[0114] When the measurement requirements are not high, it can be considered

[0115] Q 水1 =Q 水2

[0116] Q 油1 =Q 油2

[0117] Q 气1 =Q 气2

[0118] so,

[0119]

[0120]

[0121]

[0122] Then, by accumulating measurements within a set time σ, the total production of each phase of the three-phase flow of crude oil at σ=nT is obtained.

[0123]

[0124]

[0125]

[0126] The crude oil production of the pipeline in a certain period of time σ (such as hours, days, months and years) is calculated cumulatively. Setting a reasonable long time can better eliminate the interference and errors caused by fluctuations.

[0127] In addition, the control and data processing system 5 can be a PC or an embedded control system, which can output logical instructions in steps to control the opening and closing of each valve in the entire device; at the same time, it collects the information transmitted by the flow rate detection module 2, the moisture content detection module 3, and the liquid level detection module 4 in real time, and analyzes and calculates the result information such as the specific gravity and flow rate according to the above principles; and then transmits it to the user through the display device.

[0128] The method for detecting the ratio of the three-phase system of oil, water and gas by using a pipeline crude oil liquid volume measuring device specifically comprises the following steps:

[0129] Step 1: Open the flow rate detection module 2, measure and calculate the current flow rate, and when the liquid slowly flows through the test area pipeline, close the left electronic valve 22 and the right electronic valve 23 on both sides and let it stand.

[0130] Step 2: Open the outlet valve 21 and the inlet valve 18, and read the barometer 19 to control the air pressure at 1 atmosphere. Close the outlet valve 21 and the inlet valve 18, and then open the liquid level detection module valve 20 to measure the liquid level.

[0131] Step 3: Open the water content detection module 3, process the measurement results through the control and data processing system 5, and finally calculate the proportion of gas, oil and water in the device, as well as the flow rate during the measurement stage.

[0132] Step 4: Close the liquid level detection module valve 20 and the barometer 19, open the left electronic valve 22 and the right electronic valve 23 on both sides of the pipeline, calculate the flow rate and total volume of each phase during the dual-channel working time, and wait for the next measurement time to arrive.

[0133] The present invention utilizes capacitance in combination with ultrasound to achieve non-separation real-time online non-destructive detection of the respective oil, water and gas content and flow rate under low-speed near-laminar flow. The device has the characteristics of small size, low cost, easy installation and strong applicability. The invention is economical, convenient and practical with strong universality.

[0134] Example 1

[0135] The two branches of the double branch pipeline 1 have an angle of 5°, the main pipeline has a diameter of 10 cm, a thickness of 10 mm, and a length of 50 cm, and the branch part has a diameter of 6.2 cm, a thickness of 10 mm, and a length of 150 cm, and is made of resin (nylon or acrylic) material. The oil pipeline at the pipeline inlet is extended with a metal braided hose, which is 3 meters long and has the same diameter as the main pipeline, and the interface is connected with a flange.

[0136] The ultrasonic sensor 15 used in the liquid level detection module 4 is a CUM18-M1DV sensor of Shanghai Hanxi Sensor Co., Ltd. The ultrasonic sensor 15 uses the ADS1115 chip for data acquisition. Capacitor plate I8, capacitor plate II9, capacitor plate III12, capacitor plate IV13, capacitor plate V16 and capacitor plate VI17 are all 7×3cm copper plates, 1mm thick, and wrapped with insulating materials on the outer layer. Capacitor sensor I7, AD acquisition module I10, capacitor sensor II11 and AD acquisition module II14 are replaced by the AD5933 chip that can measure capacitance and convert capacitance value into digital quantity. Capacitor plate V16 and capacitor plate VI17 use the Pcap04 chip for capacitance measurement. Temperature compensation and data acquisition are capacitor sensor III24, AD acquisition module III25 and temperature sensor 26, where temperature sensor 26 is a PT1000 platinum thermal resistor, which can be connected to the temperature interface of the Pcap04 chip. The control and data processing system 5 uses STM32H750VBT6 as the main control to realize the whole machine control.

[0137] When the flow rate detection module 2 is working, the control and data processing system 5 processes the data collected by the AD5933 chip to calculate the flow rate at the current moment.

[0138] The water content detection module 3 is used to measure the oil-water ratio in the pipe. The control and data processing system 5 issues instructions to control the Pcap04 chip and the capacitive sensor to measure the liquid, and feeds the results back to the control and data processing system 5 for data processing.

[0139] The ultrasonic sensor 15 is installed in a conical cavity above the measuring pipe. The cavity is 7 cm high, with a cone angle of 10°, an upper radius of 1 cm, and a lower radius of 2.5 cm. It is connected to the liquid level detection module valve 20. The control and data processing system 5 controls the ultrasonic detection device to emit ultrasound, which is reflected back after encountering the liquid surface to obtain the liquid level height and calculate the gas proportion.

[0140] Combining the measurement results of the water content detection module 3 and the liquid level detection module 4, the liquid level height and the proportion of each phase of the three-phase flow can be obtained. Then, according to the data processing results of the flow rate detection module 2, the flow rate of the three-phase flow is obtained, and then the flow rate is calculated. In the data calculation, the three-phase flow of the two pipelines is considered to be consistent, that is, β = 1.

[0141] The pipeline crude oil liquid volume measuring device of the present invention is used for detecting three-phase flow in a near-laminar state of a production and transportation pipeline, and can measure the flow rate, liquid level, proportion of each phase and flow rate of the liquid phase. This device adopts a non-separation method, non-contact detection, easy disassembly of the device, no radiation pollution, and has broad application prospects.

[0142] Note that the above are only preferred embodiments of the present invention and the technical principles used. Those skilled in the art will understand that the present invention is not limited to the specific embodiments described herein, and that various obvious changes, readjustments and substitutions can be made by those skilled in the art without departing from the scope of protection of the present invention. Therefore, although the present invention has been described in more detail through the above embodiments, the present invention is not limited to the above embodiments, and may include more other equivalent embodiments without departing from the concept of the present invention, and the scope of the present invention is determined by the scope of the appended claims.

Claims

1. A pipeline crude oil liquid volume measuring device, characterized in that: It comprises a double-branch pipeline (1), a flow rate detection module (2), a water content detection module (3), a liquid level detection module (4) and a control and data processing system (5); The dual-branch pipeline (1) is divided into two identical branches from the main pipeline; the flow rate detection module (2), the water content detection module (3) and the liquid level detection module (4) are installed on any branch measuring pipeline of the dual-branch pipeline (1); the flow rate detection module (2) is used to measure the flow rate of the liquid in the pipeline; the water content detection module (3) is used to measure the water content of the liquid phase; the liquid level detection module (4) can measure the liquid level height, which is used to calculate the liquid phase density and gas content, and its exhaust system (6) can discharge excess gas so that the air pressure in the sampling space is maintained at a standard atmospheric pressure during measurement; the sensors in the flow rate detection module (2), the water content detection module (3) and the liquid level detection module (4) collect data and send them to the control and data processing system (5) for data processing to obtain the flow rate, liquid level height, three-phase flow volume ratio and flow rate; The double branch pipeline (1) is a group of symmetrical cylindrical pipelines made of non-metal, connected to the main pipeline, the branch angle γ of the double branch pipeline (1) is in the range of 5°-10°, the cross-sectional area of ​​the branch circular pipeline is 1 / 2-1 times that of the main pipeline, and an extended oil pipeline can be added to the front end of the main pipeline to extend the length of the crude oil flowing into the measuring pipeline; The flow rate detection module (2), the water content detection module (3) and the liquid level detection module (4) are all installed outside the pipeline. Starting from the branch part of the main pipeline, the measurement pipeline is provided with the flow rate detection module (2), the left electronic valve (22), the water content detection module (3), the barometer (19), the liquid level detection module (4), the air extraction valve (21) and the right electronic valve (23) in sequence. The outer side of the right electronic valve (23) is the air intake valve (18), which is responsible for discharging the excess gas in the measurement interval to the main pipeline. The flow rate detection module (2) is composed of two groups of capacitors, two groups of capacitor sensors and two AD acquisition modules. The two groups of capacitor plates are formed into a ring and embedded in the outer wall of the pipeline. The two groups of capacitor sensors are placed at a distance L in the pipeline. The distance between the left electronic valve (22) and the right electronic valve (23) is 0.5-5m, and the distance between the barometer (19) and the air extraction valve (21) is greater than 50cm. The water content detection module (3) is composed of capacitors, capacitor sensors III (24), AD acquisition modules. The device is composed of a module III (25) and a temperature sensor (26), two capacitor plates are respectively embedded in the left and right sides of the measuring pipeline, and the control and data processing are performed by a control and data processing system (5). The inlet and outlet sides of the measuring pipeline are connected to the left electronic valve (22) and the right electronic valve (23). The top side of the measuring pipeline is provided with a barometer (19) and a liquid level detection module (4); the liquid level detection module (4) includes an exhaust system (6) and an ultrasonic sensor (15). When working, the exhaust system (6) exhausts the air pressure in the pipeline measurement area to one atmosphere, providing a standard working air pressure condition for the ultrasonic sensor (15), and the ultrasonic sensor (15) measures the current liquid level height; the ultrasonic sensor (15) is installed in a conical cavity, the cavity height is greater than the ultrasonic sensor blind area, and is 5-20 cm, the cone angle of the conical cavity is between 10° and 20°, and is connected to the liquid level detection module valve (20); the ultrasonic sensor (15) is arranged above the measuring pipeline and is more than 5 cm away from the measuring pipeline.

2. A pipeline crude oil liquid volume measuring device according to claim 1, characterized in that: The control and data processing system (5) is a PC or an embedded control system, which can output logic instructions to control the opening and closing of each valve of the entire device; at the same time, it collects information transmitted by the flow rate detection module (2), the water content detection module (3), and the liquid level detection module (4) in real time, analyzes and calculates the specific gravity and flow rate result information of each component, and then transmits it to the user through the display device.

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