Oil-gas fluid metering device with replaceable throat diameter and metering method

Abstract

The invention provides an oil gas fluid metering device and metering method capable of changing the throat diameter, the oil gas fluid metering device comprises a Venturi tube, a detachable nozzle, a sound velocity measuring mechanism and a density measuring mechanism, an upstream flange and a downstream flange which are used for being connected with a to-be-measured pipeline are arranged at the two ends of the Venturi tube, and the detachable nozzle is installed in the middle of the Venturi tube; the flow control mechanism is used for controlling the flow of the oil-gas fluid, the sound velocity measurement mechanism is installed at the downstream position of a disassembly nozzle of the Venturi tube and used for measuring the propagation velocity of the oil-gas fluid, and the density measurement mechanism is installed at the upstream position of the disassembly nozzle of the Venturi tube and used for measuring the density of the oil-gas fluid. According to the oil-gas fluid metering device with the replaceable throat diameter and the metering method, the replaceable detachable nozzle is arranged, so that the throat diameter is changed under the condition that the whole Venturi tube is not replaced, the flow application range is expanded, and the metering efficiency is improved. The problem that the flow adaptation range is narrow due to the fact that the size of the throat of the Venturi tube is fixed in the prior art is solved.

Description

Technical Field

[0001] The present invention relates to the technical field of multiphase fluid metering, and particularly to an oil and gas fluid metering device with a replaceable throat diameter. At the same time, the present invention also relates to an oil and gas fluid metering method applied to the oil and gas fluid metering device with a replaceable throat diameter. Background Art

[0002] Gas-liquid two-phase flow widely exists in many industrial fields such as petroleum, chemical industry, and nuclear energy. In a system with two-phase flow, the flow metering of the two-phase fluid is generally unavoidable and has always been a difficult problem that has not been well solved. Multiphase flow measurement methods can generally be divided into three types according to whether separation is performed and the degree of separation: complete separation, non-separation method, and split-flow and phase-separation method.

[0003] The complete separation method is to use a separation device to separate the oil and gas fluid into single-phase gas and single-phase liquid, and then measure it through an ordinary single-phase flowmeter. Thus, the measurement of two-phase flow is transformed into the measurement of single-phase flow, which has the advantages of reliable operation, high measurement accuracy, wide measurement range, and being unaffected by the change of gas-liquid two-phase flow pattern. The biggest disadvantage of the complete separation method is that the separation device is large in volume, expensive in price, and requires the establishment of a dedicated metering station and test pipeline, which greatly increases the development cost of the flowmeter.

[0004] The non-separation method directly places the measuring instrument in the two-phase fluid for measurement, which is the mainstream method of multiphase metering in the current industrial field. This method does not require a separation device, so it is small in volume and compact in structure. The total gas-liquid flow is usually measured by throttling devices such as Venturi tubes, and the phase fraction is measured by a gamma-ray phase fraction sensor. In current non-separation multiphase metering, due to the fixed throat size of the Venturi tube, its flow adaptation range is narrow, and at the same time, the gamma-ray technology has a large radiation risk, resulting in great difficulty in popularization and application. Summary of the Invention

[0005] In view of this, one of the purposes of the present invention is to provide an oil and gas fluid metering device with a replaceable throat diameter to solve the problems in the prior art that the throat size of the Venturi tube is fixed, resulting in a narrow flow adaptation range, and the use of gamma-ray technology has a large radiation risk.

[0006] To achieve one of the above purposes, the present invention provides an oil and gas fluid metering device with a replaceable throat diameter, adopting the following technical solution:

[0007] An oil and gas fluid metering device with a replaceable throat diameter, comprising:

[0008] Pipeline to be measured; Venturi tube with upstream flange and downstream flange at both ends for connecting the pipeline to be measured; Demountable nozzle installed in the middle of the Venturi tube to control the flow rate of oil and gas fluid; Sonic velocity measuring mechanism installed downstream of the demountable nozzle of the Venturi tube to measure the propagation velocity of the oil and gas fluid; Density measuring mechanism installed upstream of the demountable nozzle of the Venturi tube to measure the density of the oil and gas fluid.

[0009] By adopting the above technical solution, without replacing the entire Venturi tube, the throat diameter can be changed by replacing the demountable nozzle, thus expanding the flow rate adaptation range and solving the problem of narrow flow rate adaptation range caused by the fixed throat size of the Venturi tube in the prior art; at the same time, the sonic velocity measuring mechanism and the density measuring mechanism are used instead of the gamma-ray technology for measurement, avoiding the radiation risk and improving the safety.

[0010] Furthermore, the Venturi tube successively includes from upstream to downstream:

[0011] Inlet straight pipe section fixedly connected to the upstream flange, and the density measuring mechanism is communicated with the inlet straight pipe section; Converging section with the large-diameter end fixedly connected to the inlet straight pipe section and the small-diameter end hermetically connected to the demountable nozzle; Throat with one end hermetically connected to the demountable nozzle, and the sonic velocity measuring mechanism is communicated with the throat; Diverging section with the small-diameter end fixedly connected to the other end of the throat; Outlet straight pipe section with one end fixedly connected to the large-diameter end of the diverging section and the other end fixedly connected to the downstream flange.

[0012] By adopting the above technical solution, the structure of the Venturi tube is more reasonable, which can better adapt to the flow characteristics of the oil and gas fluid and improve the measurement accuracy.

[0013] Furthermore, the sonic velocity measuring mechanism includes:

[0014] Ultrasonic transmitting probe and ultrasonic receiving probe respectively installed upstream and downstream of the throat to measure the sonic velocity of the oil and gas fluid; Temperature sensor installed at the inlet straight pipe section to cooperate with the ultrasonic transmitting probe and the ultrasonic receiving probe to measure the sonic velocity of the gas phase and the sonic velocity of the liquid phase respectively.

[0015] By adopting the above technical solution, the sonic velocity of the oil and gas fluid can be accurately measured, providing accurate data support for subsequent flow rate calculation. At the same time, the setting of the temperature sensor can consider the influence of temperature on the sonic velocity, further improving the measurement accuracy.

[0016] Furthermore, the density measuring mechanism includes:

[0017] An upstream pressure guiding pipe, which is communicated with the inlet straight pipe section; a pressure sensor, which is installed on the upstream pressure guiding pipe to measure the pressure at the inlet straight pipe section.

[0018] By adopting the above technical solution, the density of the oil and gas fluid can be accurately measured, providing accurate data support for subsequent flow calculation.

[0019] Furthermore, it further includes: a differential pressure sensor, which measures the differential pressure of the Venturi tube. The high-pressure end of the differential pressure sensor is communicated with the upstream pressure guiding pipe, and a middle pressure guiding pipe is provided at the throat, and the low-pressure end of the differential pressure sensor is communicated with the middle pressure guiding pipe.

[0020] By adopting the above technical solution, the differential pressure of the Venturi tube can be measured, providing important parameters for flow calculation and further improving the accuracy of flow measurement.

[0021] Furthermore, the disassembly nozzle is mainly composed of a throttle pipe and a diffuser pipe. The outlet of the throttle pipe is communicated with the inlet of the diffuser pipe. The throttle pipe is installed on the inlet straight pipe section, and the diffuser pipe is installed at the throat.

[0022] By adopting the above technical solution, the structure of the disassembly nozzle is more reasonable, which can better control the flow rate of the oil and gas fluid and improve the accuracy of flow regulation.

[0023] Compared with the prior art, one of the purposes of the present invention has the following beneficial effects:

[0024] For the oil and gas fluid metering device with a replaceable throat diameter size described in the present invention, by setting a replaceable disassembly nozzle, the throat diameter size can be changed without replacing the entire Venturi tube, expanding the flow rate adaptation range and solving the problem of narrow flow rate adaptation range caused by the fixed throat size of the Venturi tube in the prior art; using a sonic velocity measuring mechanism and a density measuring mechanism to replace the gamma ray technology for measurement, avoiding radiation risks and improving safety; the structure design of the Venturi tube is reasonable, which can better adapt to the flow characteristics of the oil and gas fluid and improve the measurement accuracy; the setting of the sonic velocity measuring mechanism and the density measuring mechanism can accurately measure the sonic velocity and density of the oil and gas fluid, providing accurate data support for flow calculation; the setting of the differential pressure sensor can measure the differential pressure of the Venturi tube and further improve the accuracy of flow measurement; the structure design of the disassembly nozzle is reasonable, which can better control the flow rate of the oil and gas fluid and improve the accuracy of flow regulation.

[0025] The second purpose of the present invention is to provide an oil and gas fluid metering method to solve the problems of low accuracy and poor adaptability in the flow metering of gas-liquid two-phase flow in the prior art.

[0026] To achieve the second purpose, the present invention provides an oil and gas fluid metering method, adopting the following technical solution:

[0027] An oil and gas fluid metering method includes the following steps:

[0028] S1. Determine the diameter D of the pipeline to be measured, the sound path L between the ultrasonic emission probe and the ultrasonic reception probe, the propagation speed C of ultrasonic waves in the liquid phase L and the propagation speed C of ultrasonic waves in the gas phase G as well as the relationship with temperature change, the liquid phase density ρ L and the gas phase density ρ G as well as the relationship with temperature and pressure change;

[0029] S2. Collect the pressure P measured by the pressure sensor, the temperature T measured by the temperature sensor, and the propagation time difference Δt between the ultrasonic waves from the ultrasonic emission probe to the ultrasonic reception probe;

[0030] S3. Calculate the gas phase density and the liquid phase density based on the pressure P and the temperature T in combination with the relationship with temperature and pressure in S1; calculate the propagation speed C of ultrasonic waves in the liquid phase based on the temperature T in combination with the temperature change relationship in S1 L and the propagation speed C of ultrasonic waves in the gas phase G ;

[0031] S4. Calculate the sound speed of the oil and gas fluid at the throat according to the following formula:

[0032]

[0033] S5. Substitute the sound speed of the oil and gas fluid into the volume gas holdup calculation formula to calculate the volume gas holdup β;

[0034] S6. Calculate the gas phase mass gas holdup x using the mass gas holdup calculation formula based on the relationship between the volume gas holdup and the mass gas holdup G ;

[0035] S7. Calculate the mass flow rate M of the oil and gas fluid using the oil and gas fluid mass flow rate formula based on the relationship between the gas phase mass gas holdup x G and the differential pressure ΔP G+L ; G+L ;

[0036] S8. Calculate the gas phase flow rate M G and the liquid phase flow rate M L respectively according to the following two formulas:

[0037] M G = M G+L x G

[0038] M L = M G+L (1 - x G ).

[0039] By adopting the above technical solution, the influence of various parameters on the flow rate is comprehensively considered, and the mass flow rate, gas-phase flow rate and liquid-phase flow rate of the oil-gas fluid can be accurately calculated, improving the accuracy and reliability of the flow rate measurement.

[0040] Further, the gas volume fraction β in S5 is calculated by the following formula:

[0041]

[0042] In the formula: C m is the sound velocity of the oil-gas fluid, in m / s; C G is the sound velocity of the gas phase, in m / s; C L is the sound velocity of the liquid phase, in m / s; β is the gas volume fraction; ρ G is the gas-phase density, in kg / m3; ρ L is the liquid-phase density, in kg / m3.

[0043] By adopting the above technical solution, the gas volume fraction can be calculated more accurately, providing accurate basic data for subsequent calculation of the gas mass fraction and flow rate.

[0044] Further, the gas mass fraction x in S6 G is calculated by the following formula:

[0045]

[0046] In the formula: x G is the gas mass fraction; β is the gas volume fraction; ρ G is the gas-phase density, in kg / m3; ρ L is the liquid-phase density, in kg / m3.

[0047] By adopting the above technical solution, the gas mass fraction can be calculated more accurately, further improving the accuracy of the flow rate calculation.

[0048] Further, the mass flow rate M of the oil-gas fluid in S7 G+L is calculated by the following formula:

[0049] In the formula: △P G+L is the differential pressure of the oil-gas fluid, in Pa; M G+L is the mass flow rate of the oil-gas fluid, in kg / s; A and B are coefficients obtained through experimental calibration.

[0050] By adopting the above technical solution, the mass flow rate of the oil-gas fluid can be calculated more accurately, providing a reliable method for the metering of the oil-gas fluid.

[0051] Compared with the prior art, the second object of the present invention has the following beneficial effects:

[0052] In the oil and gas fluid metering method of the present invention, the influence of various parameters on the flow rate is comprehensively considered, and the mass flow rate, gas phase flow rate and liquid phase flow rate of the oil and gas fluid can be accurately calculated, improving the accuracy and reliability of flow measurement; the calculation formula of the volume gas content rate can more accurately calculate the volume gas content rate, providing accurate basic data for subsequent calculation of the mass gas content rate and flow rate; the calculation formula of the gas phase mass gas content rate can more accurately calculate the gas phase mass gas content rate, further improving the accuracy of flow rate calculation; the calculation formula of the oil and gas fluid mass flow rate can more accurately calculate the mass flow rate of the oil and gas fluid, providing a reliable method for metering the oil and gas fluid; this method is applicable to various working conditions and has wide applicability; the coefficients A and B obtained through experimental calibration can further improve the accuracy of flow rate calculation. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] The drawings constituting a part of the present invention are used to provide a further understanding of the present invention. The schematic embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation to the present invention.

[0054] In the drawings:

[0055] Figure 1 is an overall schematic diagram of the oil and gas fluid metering device with a replaceable throat diameter according to Embodiment 1 of the present invention;

[0056] Figure 2 is a main sectional view of the disassembled nozzle according to Embodiment 1 of the present invention;

[0057] Figure 3 is a side sectional view of the disassembled nozzle according to Embodiment 1 of the present invention.

[0058] Description of the reference numerals in the drawings:

[0059] 1, Venturi tube; 2, Upstream flange; 3, Downstream flange; 4, Temperature sensor; 5, Pressure sensor; 6, Differential pressure sensor; 7, Ultrasonic emission probe; 8, Ultrasonic receiving probe; 9, Inlet straight pipe section; 10, Converging section; 11, Throat; 12, Diverging section; 13, Outlet straight pipe section; 14, Upstream pressure guiding pipe; 15, Middle pressure guiding pipe; 16, Disassembled nozzle; 17, Throttle pipe; 18, Expansion pipe; 19, Thread; 20, Groove. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0060] It should be noted that, without conflict, the embodiments in the present invention and the features in the embodiments can be combined with each other.

[0061] In the description of the present invention, it should be noted that if terms indicating orientation or positional relationship such as "upper", "lower", "inner", "back", etc. appear, they are based on the orientation or positional relationship shown in the drawings, and are only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore cannot be construed as a limitation of the present invention. In addition, if terms such as "first", "second", etc. appear, they are also only for descriptive purposes and cannot be construed as indicating or implying relative importance.

[0062] In addition, in the description of the present invention, unless otherwise clearly defined, the terms "installation", "connection", and "coupling" should be understood in a broad sense. For example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be directly connected or indirectly connected through an intermediate medium, and it can be the communication inside two elements. For those of ordinary skill in the art, the specific meanings of the above terms in the present invention can be understood in combination with specific situations.

[0063] The present invention will be described in detail below with reference to the drawings and in conjunction with embodiments.

[0064] Embodiment 1

[0065] This embodiment relates to an oil and gas fluid metering device with a replaceable throat diameter. In terms of the overall structure, as Figure 1 shown, it includes a Venturi tube 1, a detachable nozzle 16, a sound velocity measuring mechanism, and a density measuring mechanism.

[0066] Among them, upstream flanges 2 and downstream flanges 3 for connecting the pipeline to be measured are provided at both ends of the Venturi tube 1. The detachable nozzle 16 is installed in the middle of the Venturi tube 1 to control the flow rate of the oil and gas fluid. The sound velocity measuring mechanism is installed downstream of the detachable nozzle 16 of the Venturi tube 1 to measure the propagation velocity of the oil and gas fluid. The density measuring mechanism is installed upstream of the detachable nozzle 16 of the Venturi tube 1 to measure the density of the oil and gas fluid.

[0067] It is worth mentioning that the pipeline to be measured is the output pipeline of an oil well. Installing the oil and gas fluid metering device on the pipeline to be measured can measure the gas phase flow rate and the liquid phase flow rate. The Venturi tube 1 is installed on the pipeline to be measured, and the principle of the Venturi tube 1 is the same as that of the Venturi tube 1 in the prior art, which will not be elaborated here. Of course, it is necessary to weld flanges on the pipeline to be measured to facilitate the installation of the upstream flange 2 and the downstream flange 3. The sound velocity measuring mechanism and the density measuring mechanism are installed on the Venturi tube 1. When the oil and gas fluid passes through the Venturi tube 1, the sound velocity and density are measured, and the data is brought into a series of formulas to calculate the gas phase flow rate and the liquid phase flow rate. The purpose of adding the detachable nozzle 16 in the middle of the Venturi tube 1 is to ensure that the flow rate of the oil and gas fluid is controlled by replacing nozzles of different sizes.

[0068] Based on the above overall introduction, an exemplary structure of the electromagnetic wire water removal and drying equipment in this embodiment is as follows, as Figure 1 shown. The Venturi tube 1 sequentially includes, from upstream to downstream: an inlet straight pipe section 9, a converging section 10, a throat 11, a diverging section 12, and an outlet straight pipe section 13.

[0069] Among them, the inlet straight pipe section 9 is fixedly connected to the upstream flange 2, the density measurement mechanism is communicated with the inlet straight pipe section 9, the large-diameter end of the converging section 10 is fixedly connected to the inlet straight pipe section 9, the small-diameter end is hermetically connected to the dismountable nozzle 16, one end of the throat 11 is hermetically connected to the dismountable nozzle 16, the sound velocity measurement mechanism is communicated with the throat 11, the small-diameter end of the diverging section 12 is fixedly connected to the other end of the throat 11, and one end of the outlet straight pipe section 13 is fixedly connected to the large-diameter end of the diverging section 12, and the other end is fixedly connected to the downstream flange 3.

[0070] It should be noted that the inlet straight pipe section 9 and the converging section 10 can be integrally formed, the upstream flange 2 can be welded to the inlet straight pipe section 9, the throat 11, the diverging section 12, and the outlet straight pipe section 13 can also be integrally formed, and the downstream flange 3 can be welded to the outlet straight pipe section 13. Such a setting can improve the strength of the Venturi tube 1. The purpose of installing the dismountable nozzle 16 between the converging section 10 and the throat 11 is to be able to adjust the flow rate of the Venturi tube 1. By replacing the dismountable nozzles 16 with different apertures, different pressure differences can be achieved, which can meet the requirements of accurate differential pressure measurement under different gas-liquid fluid flow rates, and further achieve accurate measurement of a larger gas-liquid flow rate range.

[0071] As a preferred implementation manner, as Figure 1 shown, the sound velocity measurement mechanism in this embodiment includes: an ultrasonic emission probe 7, an ultrasonic reception probe 8, and a temperature sensor 4.

[0072] Among them, the ultrasonic emission probe 7 and the ultrasonic reception probe 8 are respectively installed at the upstream and downstream of the throat 11 for measuring the sound velocity of the oil-gas fluid. The temperature sensor 4 is installed at the inlet straight pipe section 9 to cooperate with the ultrasonic emission probe 7 and the ultrasonic reception probe 8 to respectively measure the sound velocity of the gas phase and the sound velocity of the liquid phase.

[0073] Specifically, the upstream and downstream of the throat 11 are the two sides of the throat 11. The ultrasonic emission probe 7 and the ultrasonic reception probe 8 are respectively installed on the two sides of the throat 11. Such a setting ensures that the ultrasonic waves emitted by the ultrasonic emission probe 7 can be received by the ultrasonic reception probe 8 after passing through the oil-gas fluid, so as to obtain the sound path and time, and the temperature sensor 4 measures the temperature of the oil-gas fluid at this place. According to the propagation speeds of ultrasonic waves in the gas phase and the liquid phase at different temperatures, the sound velocity of the oil-gas fluid is calculated.

[0074] As a preferred implementation manner, asFigure 1 As shown in the figure, the density measurement mechanism of this embodiment includes: an upstream pressure guiding pipe 14 and a pressure sensor 5. Among them, the upstream pressure guiding pipe 14 is communicated with the inlet straight pipe section 9, and the pressure sensor 5 is installed on the upstream pressure guiding pipe 14 to measure the pressure at the inlet straight pipe section 9. Specifically, the upstream pressure guiding pipe 14 can be welded to the inlet straight pipe section 9 of the Venturi tube 1, and the pressure sensor 5 measures the pressure at this place. In combination with the temperature measured by the temperature sensor 4, the gas phase density and the liquid phase density can be calculated.

[0075] Preferably, in this embodiment, a differential pressure sensor 6 is further provided on the Venturi tube 1, and a middle pressure guiding pipe 15 is provided at the throat 11. The high-pressure end of the differential pressure sensor 6 is communicated with the upstream pressure guiding pipe 14, and the low-pressure end is communicated with the middle pressure guiding pipe 15. It should be noted that the function of the differential pressure sensor 6 is to measure the pressure difference between the inlet straight pipe section 9 and the throat 11. Due to the principle of the Venturi tube 1, the difference in diameters between the inlet straight pipe section 9 and the throat 11 will generate a certain pressure difference. According to the pressure difference measured by the differential pressure sensor 6 and substituting the above data, the oil-gas fluid flow rate can be calculated.

[0076] As a preferred implementation manner, as Figure 2 and Figure 3 shown, the disassembly nozzle 16 of this embodiment mainly consists of a throttle pipe 17 and a diffuser pipe 18. The outlet of the throttle pipe 17 is communicated with the inlet of the diffuser pipe 18. The throttle pipe 17 is installed in the inlet straight pipe section 9, and the diffuser pipe 18 is installed at the throat 11. Specifically, the throttle pipe 17 is a circular pipe with a constant diameter, and the diffuser pipe 18 is a gradually expanding structure. Its inlet diameter is the same as the diameter of the throttle pipe 17, and its outlet diameter is the same as the diameter of the throat 11 of the Venturi tube 1. When installing the throttle pipe 17, its outer surface fits with the inner surface of the gradually reducing section 10 of the Venturi tube 1, and an interference fit can be used. When installing the diffuser pipe 18, its outer surface fits with the inner surface of the throat 11 of the Venturi tube 1. Threads 19 are provided on the outer surface of the diffuser pipe 18, and the same threads 19 are also provided on the inner surface of the throat 11. The installation is completed through the engagement of the two threads 19. At the same time, grooves 20 are provided on the outer surface of the disassembly nozzle 16 to facilitate the installation to the designated position using a large flat-head screwdriver.

[0077] In the oil and gas fluid metering device with replaceable throat diameter in this embodiment, by setting the replaceable disassembly nozzle 16, the change of the throat diameter is realized without replacing the entire Venturi tube 1, the flow rate adaptation range is expanded, and the problem of narrow flow rate adaptation range caused by the fixed size of the throat 11 of the Venturi tube 1 in the prior art is solved; the sonic velocity measuring mechanism and the density measuring mechanism are used to replace the gamma ray technology for measurement, avoiding the radiation risk and improving the safety; the structural design of the Venturi tube 1 is reasonable, which can better adapt to the flow characteristics of the oil and gas fluid and improve the measurement accuracy; the setting of the sonic velocity measuring mechanism and the density measuring mechanism can accurately measure the sonic velocity and density of the oil and gas fluid, providing accurate data support for flow rate calculation; the setting of the differential pressure sensor 6 can measure the differential pressure of the Venturi tube 1, further improving the accuracy of the flow rate measurement; the structural design of the disassembly nozzle 16 is reasonable, which can better control the flow rate of the oil and gas fluid and improve the accuracy of the flow rate adjustment.

[0078] Embodiment 2

[0079] This embodiment relates to an oil and gas fluid metering method. In terms of the overall structure, it includes the following steps.

[0080] S1. Determine the diameter D of the pipeline to be measured, the sound path L between the ultrasonic transmitting probe 7 and the ultrasonic receiving probe 8, the propagation speed C of ultrasonic waves in the liquid phase L and the propagation speed C of ultrasonic waves in the gas phase G as well as the relationship between the propagation speed and temperature, the liquid phase density ρ L and the gas phase density ρ G as well as the relationship between the propagation speed and temperature and pressure;

[0081] S2. Collect the pressure P measured by the pressure sensor 5, the temperature T measured by the temperature sensor 4, and the propagation time difference △t of ultrasonic waves from the ultrasonic transmitting probe 7 to the ultrasonic receiving probe 8;

[0082] S3. Calculate the gas phase density and the liquid phase density according to the pressure P and the temperature T in combination with the relationship between the propagation speed and temperature and pressure in S1; calculate the propagation speed C of ultrasonic waves in the liquid phase according to the temperature T in combination with the relationship between the propagation speed and temperature in S1 L and the propagation speed C of ultrasonic waves in the gas phase G ;

[0083] S4. Calculate the sonic velocity of the oil and gas fluid at the throat according to the following formula:

[0084]

[0085] S5. Substitute the sonic velocity of the oil and gas fluid into the volume gas holdup calculation formula to calculate the volume gas holdup β;

[0086] S6. Calculate the gas-phase mass gas holdup x according to the relationship between the volume gas holdup and the mass gas holdup, using the mass gas holdup calculation formula. G ;

[0087] S7. According to the gas-phase mass gas holdup x G and the differential pressure ΔP G+L relationship, calculate the oil-gas fluid mass flow rate M using the oil-gas fluid mass flow formula G+L ;

[0088] S8. Calculate the gas-phase flow rate M G and the liquid-phase flow rate M L respectively according to the following two equations:

[0089] M G = M G+L x G

[0090] M L = M G+L (1 - x G ).

[0091] It should be noted that after the ultrasonic emission probe 7 emits ultrasonic waves, they are received by the ultrasonic receiving probe 8 after a time Δt. If the path traveled by the ultrasonic waves between the ultrasonic emission probe 7 and the ultrasonic receiving probe 8 (i.e., the sound path L), then the ultrasonic propagation speed C in the oil-gas fluid m can be calculated using the steps in S4.

[0092] Preferably, the formula for calculating the volume gas holdup β mentioned in S5 above is:

[0093]

[0094] In the formula: C m is the sound speed of the oil-gas fluid, with the unit m / s; C G is the sound speed of the gas phase, with the unit m / s; C L is the sound speed of the liquid phase, with the unit m / s; β is the volume gas holdup; ρ G is the gas-phase density, with the unit kg / m 3 ; ρ L is the liquid-phase density, with the unit kg / m 3 .

[0095] Specifically, the relationship between the propagation speed C L of the ultrasonic waves in the liquid phase in S1 and the propagation speed C G of the ultrasonic waves in the gas phase with temperature change, the liquid-phase density ρ L and the relationship between the gas-phase density ρ G with temperature and pressure change can be obtained through experiments.

[0096] For the liquid phase, the relationship between the speed of sound and temperature is usually expressed by a linear empirical formula: vt = v0 + α(t - t0).

[0097] Where, vt is the speed of sound at temperature t, with the unit of m / s; v is the speed of sound at the reference temperature t0, with the unit of m / s; α is the temperature coefficient, representing the change in the speed of sound per 1°C increase, with the unit of m / (s·°C); t0 is the reference temperature, with the unit of °C.

[0098] For the gas phase, if it is regarded as an ideal gas, its speed of sound expression is: c = γRT.

[0099] Where, γ is the adiabatic index (specific heat ratio) of air. For diatomic gases (such as air), γ = 1.4; R is the gas constant, and for air, R = 287 J / (kg·K); T is the absolute temperature, with the unit of K.

[0100] Calculate the sound speed C of the oil-gas fluid according to the sound speed of the single-phase medium m , and substituting the calculation result into the above formula can obtain the volume gas holdup β.

[0101] Preferably, the formula for calculating the gas mass fraction x mentioned in the above S6 G is as follows:

[0102]

[0103] In the formula: x G is the gas mass fraction; β is the volume gas holdup; ρ G is the gas density, with the unit of kg / m 3 ; ρ L is the liquid density, with the unit of kg / m 3 .

[0104] Specifically, the gas mass fraction is a function of the volume gas holdup and the gas and liquid densities. Substituting the calculation result of the volume gas holdup β into the above formula can obtain the mass fraction x G .

[0105] Preferably, the formula for calculating the mass flow rate M of the oil-gas fluid mentioned in the above S7 G+L is as follows:

[0106]

[0107] In the formula: △P G+L is the differential pressure of the oil-gas fluid, with the unit of Pa; M G+L is the mass flow rate of the oil-gas fluid, with the unit of kg / s; A and B are coefficients obtained through experimental calibration.

[0108] Specifically, when the oil-gas fluid passes through the Venturi tube, a pressure drop (i.e., differential pressure △P G+L), the differential pressure △P of the oil-gas fluid G+L and the gas-phase mass gas holdup x G are substituted into the above formula to obtain the mass flow rate M of the oil-gas fluid G+L , where A and B in the formula are coefficients. By measuring the true gas-liquid mass flow rate M G+L , the gas-phase mass gas holdup x G , and the differential pressure △P G+L , the coefficients A and B can be obtained by least squares fitting.

[0109] The oil-gas fluid metering method in this embodiment comprehensively considers the influence of various parameters on the flow rate, can accurately calculate the mass flow rate, gas-phase flow rate and liquid-phase flow rate of the oil-gas fluid, and improves the accuracy and reliability of flow rate measurement; the calculation formula of the volume gas holdup can more accurately calculate the volume gas holdup, providing accurate basic data for subsequent mass gas holdup and flow rate calculations; the calculation formula of the gas-phase mass gas holdup can more accurately calculate the gas-phase mass gas holdup, further improving the accuracy of flow rate calculation; the calculation formula of the oil-gas fluid mass flow rate can more accurately calculate the mass flow rate of the oil-gas fluid, providing a reliable method for metering the oil-gas fluid; this method is applicable to various working conditions and has wide applicability; the coefficients A and B obtained through experimental calibration can further improve the accuracy of flow rate calculation.

[0110] The above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. An oil and gas fluid metering device with a replaceable throat diameter, characterized in that, Comprising: The pipeline to be measured; A Venturi tube (1) with an upstream flange (2) and a downstream flange (3) provided at both ends for connecting to the pipeline to be measured; A dismountable nozzle (16) installed in the middle of the Venturi tube (1) for controlling the flow rate of the oil-gas fluid; A sound velocity measuring mechanism installed downstream of the dismountable nozzle (16) of the Venturi tube (1) for measuring the propagation velocity of the oil-gas fluid; A density measuring mechanism installed upstream of the dismountable nozzle (16) of the Venturi tube (1) for measuring the density of the oil-gas fluid.

2. The replaceable orifice size oil and gas fluid metering device according to claim 1, characterized in that, The Venturi tube (1) sequentially includes from upstream to downstream: An inlet straight pipe section (9) fixedly connected to the upstream flange (2), and the density measuring mechanism is communicated with the inlet straight pipe section (9); A converging section (10) with its large-diameter end fixedly connected to the inlet straight pipe section (9) and its small-diameter end hermetically connected to the dismountable nozzle (16); A throat (11) with one end hermetically connected to the dismountable nozzle (16), and the sound velocity measuring mechanism is communicated with the throat (11); A diverging section (12) with its small-diameter end fixedly connected to the other end of the throat (11); An outlet straight pipe section (13) with one end fixedly connected to the large-diameter end of the diverging section (12) and the other end fixedly connected to the downstream flange (3).

3. The replaceable orifice size oil and gas fluid metering device according to claim 2, wherein, The sound velocity measuring mechanism includes: An ultrasonic transmitting probe (7) and an ultrasonic receiving probe (8) respectively installed upstream and downstream of the throat (11) for measuring the sound velocity of the oil-gas fluid; A temperature sensor (4) installed at the inlet straight pipe section (9) to cooperate with the ultrasonic transmitting probe (7) and the ultrasonic receiving probe (8) to respectively measure the sound velocity of the gas phase and the sound velocity of the liquid phase.

4. The replaceable orifice-size oil and gas fluid metering device according to claim 2, wherein The density measuring mechanism includes: An upstream pressure guiding pipe (14) communicated with the inlet straight pipe section (9); A pressure sensor (5) installed on the upstream pressure guiding pipe (14) for measuring the pressure at the inlet straight pipe section (9).

5. The replaceable orifice size oil and gas fluid metering device according to claim 2, characterized in that, It further includes: A differential pressure sensor (6) for measuring the differential pressure of the Venturi tube (1). The high-pressure end of the differential pressure sensor (6) is communicated with the upstream pressure guiding pipe (14), and a middle pressure guiding pipe (15) is provided at the throat (11), and the low-pressure end of the differential pressure sensor (6) is communicated with the middle pressure guiding pipe (15).

6. The oil-gas fluid metering device with a replaceable throat diameter size according to claim 2, wherein: The dismountable nozzle (16) is mainly composed of a throttle pipe (17) and a diffuser pipe (18). The outlet of the throttle pipe (17) is communicated with the inlet of the diffuser pipe (18). The throttle pipe (17) is installed at the inlet straight pipe section (9), and the diffuser pipe (18) is installed at the throat (11).

7. A method for measuring oil and gas fluid, characterized in that: Including the following steps: S1. Determine the diameter D of the pipeline to be measured, the sound path L between the ultrasonic transmitting probe (7) and the ultrasonic receiving probe (8), the propagation speed C of ultrasonic waves in the liquid phase L and the propagation speed C of ultrasonic waves in the gas phase G The relationship of change with temperature, the liquid phase density ρ L and the gas phase density ρ G The relationship of change with temperature and pressure; S2. Collect the pressure P measured by the pressure sensor (5), the temperature T measured by the temperature sensor (4), and the propagation time difference △t between the ultrasonic wave from the ultrasonic transmitting probe (7) to the ultrasonic receiving probe (8); S3. Calculate the gas-phase density ρ according to the pressure P and temperature T in combination with the relationship formula that varies with temperature and pressure in S1 G and the liquid-phase density ρ L ; Calculate the propagation speed C of ultrasonic waves in the liquid phase according to the temperature T in combination with the temperature change relationship formula in S1 L and the propagation speed C of ultrasonic waves in the gas phase G ; S4. Calculate the sound velocity of the oil-gas fluid at the throat according to the following formula: S5. Substitute the sound velocity of the oil-gas fluid into the volume gas content calculation formula to calculate the volume gas content β; S6. According to the relationship between the volume gas holdup and the mass gas holdup, calculate the gas phase mass gas holdup x using the mass gas holdup calculation formula G ; S7. According to the gas mass fraction in the gas phase x G and the differential pressure △P G+L relationship, use the oil-gas fluid mass flow formula to calculate the oil-gas fluid mass flow M G+L ; S8. Calculate the gas-phase flow rate M and the liquid-phase flow rate M respectively according to the following two equations: G and L : M G = M G+L x G M G = M G+L (1 - x G ) 8. The oil and gas fluid metering method according to claim 7, wherein: The volumetric gas holdup β in S5 is calculated by the following formula: Where: C m is the acoustic velocity of the oil and gas fluid, with the unit of m / s; C G is the acoustic velocity of the gas phase, with the unit of m / s; C L is the acoustic velocity of the liquid phase, with the unit of m / s; β is the gas volume fraction; ρ G is the gas phase density, with the unit of kg / m 3 ; ρ L is the liquid-phase density, unit kg / m 3 .

9. The oil and gas fluid metering method according to claim 7, characterized in that: The gas mass void fraction x in S6 G is calculated by the following formula: Where: x G is the mass gas holdup; β is the volume gas holdup; ρ G is the gas phase density, with the unit of kg / m 3 ; ρ L is the liquid-phase density, unit kg / m 3 .

10. The oil and gas fluid metering method according to claim 7, wherein: The oil and gas fluid mass flow rate M in S7 G+L is calculated using the following formula: Where: △P G+L is the differential pressure of the oil and gas fluid, in Pa; M G+L is the mass flow rate of the oil and gas fluid, in kg / s; A and B are coefficients obtained through experimental calibration.

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