Multiphase flow metering system and method

Abstract

This invention provides a multiphase flow metering system and method, belonging to the field of oil and gas testing technology. The system includes a magnetic resonance multiphase flow meter and a corresponding manifold system. The manifold system includes multiple control valves and connecting pipes for controlling the flow of the corresponding fluid through the magnetic resonance multiphase flow meter. The magnetic resonance multiphase flow meter includes multiple magnet structures spaced apart along its axial direction for magnetizing the fluid. The flow meter also includes two measuring antennas spaced apart along its axial direction for detecting the phase state of the magnetized fluid. This invention provides a method for multiphase flow metering using a magnetic resonance multiphase flow meter, improving the accuracy of multiphase flow metering in oil and gas testing.

Description

Technical Field

[0001] This invention relates to the field of oil and gas testing technology, and specifically to a multiphase flow metering system and a multiphase flow metering method. Background Technology

[0002] Oil and gas testing is a crucial process for identifying industrial-grade oil and gas flows, determining reservoir characteristics, verifying reservoir understanding and interpretation, evaluating reservoir development value, and establishing operational procedures. It is also the first step in directly testing oil and gas-bearing strata. Multiphase flow meters can replace traditional test separators for exploration oil testing, significantly simplifying equipment and processes, reducing testing time, substantially saving investment, lowering operating costs, shortening oilfield construction cycles, and improving reservoir evaluation and management. However, the high flow rate, high pressure, and complex fluid dynamics and composition are the most prominent characteristics that distinguish oil and gas testing from production measurement. Currently, there is no accurate method for measuring oil and gas using multiphase flow meters to address these characteristics. Therefore, a new multiphase flow metering method is needed. Summary of the Invention

[0003] The purpose of this invention is to provide a multiphase flow metering method and system to at least solve the current problem of inaccurate oil and gas testing metering.

[0004] To achieve the above objectives, a first aspect of the present invention provides a multiphase flow metering system, the multiphase flow metering system comprising: a magnetic resonance multiphase flow meter and a correspondingly configured manifold system; the manifold system comprising multiple control valves and connecting pipes for controlling the flow of a corresponding fluid through the magnetic resonance multiphase flow meter; the magnetic resonance multiphase flow meter comprising multiple magnet structures spaced apart along the axial direction of the magnetic resonance multiphase flow meter for magnetizing the fluid; the magnetic resonance multiphase flow meter further comprising two measuring antennas spaced apart along the axial direction of the magnetic resonance multiphase flow meter for detecting the phase state of the magnetized fluid.

[0005] Optionally, the manifold system includes: a measurement trunk line and measurement branches; the measurement trunk line is formed by sequentially connecting the following components: a first three-way valve, a two-way valve, a second three-way valve, and a third three-way valve; the magnetic resonance multiphase flow meter is disposed between the two-way valve and the second three-way valve; the measurement branches include: a fourth three-way valve and a pressure-limiting safety valve; the measurement branches are connected in parallel to the measurement trunk line through the third port of the first three-way valve, the third port of the second three-way valve, and the third port of the third three-way valve.

[0006] Optionally, the opening and closing states of the first, second, third, and fourth three-way valves are determined by the fluid detection state. Specifically, if the fluid is detected to be flowing, then: the first, third, and fourth three-way valves are in a three-way state; the second three-way valve is in a horizontal double-way state; the two-way valve is in an open state; and the pressure-limiting safety valve is in a closed state. If the fluid is detected to be stationary, then: the first, third, and fourth three-way valves are in a three-way state; the second three-way valve is in a state where the outlet end connected to the magnetic resonance multiphase flowmeter is closed, and the other two ends are open; the two-way valve is in a closed state; and the pressure-limiting safety valve is in a state awaiting activation. The activation condition for the pressure-limiting safety valve is that the pressure in the connecting pipeline is greater than a preset threshold.

[0007] Optionally, the rear half of the axial section of the magnetic resonance multiphase flow meter is used as the detection section, and the front half of the axial section of the magnetic resonance multiphase flow meter is used as the polarization section; the multiphase flow metering system further includes: two measuring antennas; both measuring antennas are located in the detection section of the magnetic resonance multiphase flow meter.

[0008] Optionally, the magnet structure is a ring magnet structure or a Halbach magnet structure; the magnet structures located in the polarization section of the magnetic resonance multiphase flowmeter are arranged in contact connection; the magnet structures located in the detection section of the magnetic resonance multiphase flowmeter are arranged at equal intervals.

[0009] A second aspect of the present invention provides a multiphase flow metering method, the method being implemented based on the aforementioned multiphase flow metering system, the method comprising: measuring the phase parameters of a fluid according to a selected measurement requirement and a corresponding measurement method; wherein the phase parameters are the content parameters or velocity parameters of a target phase; simultaneously acquiring the reflected signals of the fluid through two measurement antennas; and reading the phase parameters of the fluid based on the acquired reflected signals and a preset device scale.

[0010] Optionally, the measurement methods include: a moisture content measurement method, a gas phase measurement method, and a flow rate measurement method.

[0011] Optionally, the water content measurement method includes: acquiring echo trains of CPMG pulse sequences simultaneously transmitted by two measuring antennas; fitting the echo trains of the two measuring antennas respectively to obtain corresponding fitting curves; extracting the amplitude of the two fitting curves at preset times respectively; and obtaining the current water content and oil content of the fluid based on the amplitude ratio of the two fitting curves at the same time.

[0012] Optionally, the preset device scale includes: a hydrogen content index scale for oil, a hydrogen content index scale for natural gas, a length scale for the two measuring antennas, and a length scale for the effective area of ​​the magnet structure at the front end of the two measuring antennas.

[0013] Optionally, the method further includes: constructing a preset equipment calibration, including constructing a hydrogen content index for oil and a hydrogen content index for natural gas; wherein, constructing the hydrogen content index for oil includes: collecting fluid samples, obtaining the water content and oil content of the fluid samples, and obtaining the hydrogen content index of the fluid samples based on the water content and oil content; constructing the hydrogen content index of natural gas includes: measuring the water content and oil content of fluid samples at different temperatures and pressures, and obtaining the hydrogen content index of the natural gas sample to be tested based on the water content and oil content of the fluid samples at different temperatures and pressures; or filling the magnetic resonance multiphase flowmeter with fluid samples and water respectively, obtaining the initial measurement values ​​of the fluid samples and water respectively when the fluids are in a static state, and obtaining the hydrogen content index of natural gas based on the ratio of the two.

[0014] Optionally, the gas phase measurement method includes: acquiring the initial amplitude value of a multiphase flow signal collected by any measurement antenna; and obtaining the gas phase content ratio based on the initial amplitude value of the multiphase flow signal and a preset conversion relationship between the initial amplitude value and the gas phase content ratio, wherein the conversion relationship is:

[0015] R 气 +R 液 =1

[0016] M mix =R 气 *M 气 +R 液 *M 液

[0017] M 液 =R 水 *M 水 +R 油 *M 油

[0018] =R 水 *M 水 +(1-R 水 )*M 水 *HI 油

[0019] Among them, M mix R represents the initial amplitude of the measured multiphase flow signal. 气 M represents the proportion of gas phase content. 气 The first amplitude value of the multiphase flow signal is marked by the hydrogen content index of natural gas; R 液 =R 水 +R 油, represents the content ratio of the liquid phase; M 液 This is the initial signal amplitude when the connecting pipe is filled with the current oil-to-water ratio liquid phase fluid; M 水 This is the initial signal amplitude when the connecting pipe is full of oil; HI 油 The hydrogen content index of the oil is used as the scale; the gas volume fraction under standard operating conditions is obtained based on the gas phase content ratio, and the obtained gas volume fraction is used as the gas phase measurement result.

[0020] Optionally, prior to the flow velocity measurement method, the method further includes: superimposing echo train data measured by two measurement antennas, including: extracting echo train data measured by two measurement antennas; wherein the CPMG pulse sequences used by the two measurement antennas have the same number of pulses and echo interval, and a phase difference of 180°; multiplying all the echo train data of one measurement antenna by the wave number of the echo to obtain the processed echo train data of that measurement antenna; accumulating the processed echo train data of the measurement antenna with the echo train data of the other measurement antenna; and measuring the flow velocity of the fluid based on the accumulated echo train data.

[0021] On the other hand, the present invention provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described multiphase flow metering method.

[0022] The above technical solution creates a new multiphase flow metering system for phase detection of fluids using magnetic resonance technology. By enhancing the magnetization effect of the fluid through a preset magnet structure, and then using two spaced measurement antennas to simultaneously transmit echo trains of CPMG pulse sequences, phase detection is performed based on the echo trains, thus improving the detection accuracy.

[0023] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0024] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0025] Figure 1 This is a system structure diagram of a multiphase flow metering system provided in one embodiment of the present invention;

[0026] Figure 2 This is a schematic diagram of the structure of a magnetic resonance multiphase flowmeter provided in one embodiment of the present invention;

[0027] Figure 3 This is a flowchart of the steps of a multiphase flow metering method provided in one embodiment of the present invention.

[0028] Explanation of reference numerals in the attached figures

[0029] 1-Magnetic resonance multiphase flow meter; 2-First three-way valve; 3-Two-way valve; 4-Second three-way valve; 5-Third three-way valve; 6-Fourth three-way valve; 7-Pressure limiting safety valve. Detailed Implementation

[0030] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0031] Oil and gas testing is a crucial process for identifying industrial-grade oil and gas flows, determining reservoir characteristics, verifying reservoir understanding and interpretation, evaluating reservoir development value, and establishing operational procedures. It is also the first step in directly testing oil and gas-bearing strata. Multiphase flow meters can replace traditional test separators in exploration oil testing, significantly simplifying equipment and processes, reducing testing time, substantially saving investment, lowering operating costs, shortening oilfield construction cycles, and improving reservoir evaluation and management. Multiphase flow metering is a vital procedure throughout the entire oil and gas testing process. Its purpose is to monitor the real-time changes in downhole multiphase flow rate and composition during the testing phase, thereby understanding the real-time effectiveness of enhanced oil recovery (EOR) measures. The current metering method using a "three-phase separator + single-phase flow meter" at the wellhead suffers from significant drawbacks, including large equipment size, high investment costs, low accuracy, data delays, incomplete separation, and the impact of production enhancement measures on measurement accuracy. To address these issues, this paper proposes applying magnetic resonance imaging (MRI) technology to the metering and analysis of multiphase flows produced downhole during the oil and gas testing phases. This aims to achieve real-time, high-precision, high-frequency, full-range, and environmentally friendly metering of multiphase flows.

[0032] Large flow rate, high pressure, and complex fluid flow patterns and compositions are the most prominent characteristics that distinguish oil and gas testing from production testing, and also the biggest challenge faced by multiphase flow meters, for which there is currently no reliable technology.

[0033] Oil and gas testing, especially in the initial stage of oil and gas testing, involves high pipeline pressure (usually above 30MPa), large flow rate, complex flow pattern, and extremely unstable fluid phase content and flow velocity, which are in a state of instantaneous change. This places higher demands on the high frequency, speed and accuracy of multiphase flow meters.

[0034] Currently, the application of magnetic resonance multiphase flowmeters is concentrated in the production testing phase of oil and gas wells. In this phase, phase inclusion and flow rate do not change instantaneously. Therefore, a measurement mode relying on valve assemblies—"static phase inclusion + dynamic flow velocity"—is adopted. This involves sampling the production fluid through valve assemblies, sealing a section of the fluid within the magnetic resonance probe, and then performing static magnetic resonance spectroscopy analysis to obtain the phase inclusion. Then, under continuous flow conditions, the total flow velocity is measured to obtain the oil, gas, and water flow rates. The problem with this "static-dynamic switching" measurement mode is that phase inclusion and flow velocity measurements are not synchronized. Phase inclusion is measured at fixed intervals, and flow velocity is measured after a period of time, by which time the phase inclusion may have changed (more noticeable in gas wells). This measurement mode is suitable for production wells with relatively stable fluid production, but not for oil and gas testing conditions where production is unstable. Furthermore, the pressure inside the pipe is generally high during oil and gas testing, and the produced fluid contains oil solids. Frequent valve opening and closing can cause severe water hammer effects, and valve components are also prone to erosion and wear, potentially leading to dangerous gas leaks.

[0035] To address the aforementioned problems, this invention proposes a magnetic resonance multiphase flow metering method and device for oil and gas testing, enabling the application of magnetic resonance technology in the specific scenario of oil and gas testing, achieving online metering and analysis of multiphase flows. Specifically, it utilizes magnetic resonance (MR) technology. MR technology, as a mainstream indoor fluid composition analysis technique, offers advantages such as non-invasiveness, environmental friendliness, and high efficiency and accuracy. It is currently used in industrial settings for online measurement of complex multiphase fluids. Against this backdrop, the multiphase flow nuclear magnetic resonance flowmeter marks the first application of MR technology in the field of oil and gas metering.

[0036] Figure 1 This is a system structure diagram of a multiphase flow metering system provided in one embodiment of the present invention. Figure 1 As shown, this embodiment of the invention provides a multiphase flow metering system, the system comprising: a magnetic resonance multiphase flow meter 1 and a correspondingly configured manifold system; wherein, the manifold system includes multiple control valves and connecting pipes for controlling the flow of corresponding fluid through the magnetic resonance multiphase flow meter 1; the magnetic resonance multiphase flow meter 1 includes multiple magnet structures distributed along the axial spacing of the magnetic resonance multiphase flow meter 1 for magnetizing the fluid; the magnetic resonance multiphase flow meter 1 further includes two measuring antennas distributed along the axial spacing of the magnetic resonance multiphase flow meter 1 for detecting the phase state of the magnetized fluid.

[0037] Preferably, the manifold system includes: four three-way valves, one two-way valve 3, and one pressure-limiting safety valve 7; wherein, the multiphase flow metering system includes: a measurement main line and measurement branches; wherein, the connection sequence of the measurement main line is, in sequence, a first three-way valve 2, a two-way valve 3, a magnetic resonance multiphase flow meter 1, a second three-way valve 4, and a third three-way valve 5; the measurement branches include a fourth three-way valve 6 and a pressure-limiting safety valve 7; the measurement branches are connected to the measurement main line through the third port of the first three-way valve 2, the third port of the second three-way valve 4, and the third port of the third three-way valve 5.

[0038] In this embodiment of the invention, the traditional magnetic resonance multiphase flowmeter 1 faces the risk of valve failure during oil and gas testing, which may lead to poor fluid flow or even blockage in the pipeline, causing serious leakage accidents. There is a need to design a branch line structure that can effectively address overpressure issues caused by valve failure without affecting normal on-site production activities, thereby expanding the flowmeter's applicability and reducing safety risks.

[0039] Preferably, the opening and closing states of multiple valves in the manifold system are determined by the fluid detection state; wherein, if the fluid is in a flowing state, then: the first three-way valve 2, the third three-way valve 5, and the fourth three-way valve 6 are in a three-way state; the second three-way valve 4 is in a horizontal double-way state; the two-way valve 3 is in an open state; and the pressure limiting safety valve 7 is in a closed state; if the fluid is in a static state, then: the first three-way valve 2, the third three-way valve 5, and the fourth three-way valve 6 are in a three-way state; the second three-way valve 4 is in a state where the outlet end of the magnetic resonance multiphase flowmeter 1 is closed and the other two ends are open; the two-way valve 3 is in a closed state; and the pressure limiting safety valve 7 is in a state to be activated, wherein the activation condition is that the pressure in the pipeline is greater than a preset threshold.

[0040] In this embodiment of the invention, preferably, the first three-way valve 2, the third three-way valve 5, and the fourth three-way valve 6 are manual valves; the second three-way valve 4 is an electrically controlled valve; and the two-way valve 3 is an electrically controlled valve. Therefore, this branch pipe structure includes three manual three-way valves, one three-way electrically controlled valve, one two-way electrically controlled valve, and one pressure-limiting safety valve 7. When the system performs flow measurement, all three manual valves are in the three-way position, the electrically controlled three-way valve is open horizontally, and the two-way valve 3 is open. The pressure inside the pipeline is lower than the set pressure of the pressure-limiting safety valve, so the safety valve is closed; at this time, the fluid can flow through the multiphase flow meter for flow measurement. When the system performs static measurement, all three manual valves are in the three-way position, the electrically controlled three-way valve is open vertically and to the right, and the two-way valve 3 is closed. The pressure inside the pipeline is lower than the set pressure of the pressure-limiting safety valve, so the safety valve is closed; at this time, the fluid in the flow meter is static, and the fluid flows away through the branch pipe.

[0041] When two electrically controlled valves malfunction or operate out of sync, causing pressure fluctuations or increases in the pipeline, and the pressure exceeds the set pressure of the pressure-limiting safety valve, the safety valve will automatically open, releasing the pressure to the branch pipeline and keeping the pressure in the pipeline within a safe range.

[0042] When the system is undergoing equipment maintenance, the third three-way valve 5 is vertically open to the right; the fourth three-way valve 6 is horizontally open; the first three-way valve 2 is vertically open to the left; the safety valve opens automatically; at this time, the fluid flows out through the branch pipe, allowing maintenance work to be carried out on equipment such as multiphase flow meters and valves.

[0043] Preferred, such as Figure 2 Both measuring antennas are located in the rear half of the axial direction of the magnetic resonance multiphase flowmeter 1, serving as the detection section of the magnetic resonance multiphase flowmeter 1; the front half of the magnetic resonance multiphase flowmeter 1 is the polarization section.

[0044] Preferably, the multiple magnet structures located at the polarization end are arranged closely together; the multiple magnet structures located at the detection section are arranged at equal intervals; wherein, the magnet structure is a ring magnet structure or a Halbach magnet structure.

[0045] In this embodiment of the invention, the fluid flow rate is relatively fast during the oil and gas testing phase, and the time from when the fluid flows into the magnet to when it reaches the antenna is short, i.e., the magnetization time is short and the magnetization efficiency is low, resulting in low amplitude of the acquired signal and low signal-to-noise ratio, affecting the measurement accuracy. Therefore, it is necessary to improve the magnetization efficiency of the fluid. There are two methods: one is to reduce the flow rate, and the other is to increase the static magnetic field strength. The former can be achieved by increasing the inner diameter of the pipe, but this has many engineering problems. For example, during the gas testing, a sudden change in pipe diameter will cause a large temperature change in the high-pressure gas, affecting the measurement accuracy. At the same time, a larger pipe means a larger magnet volume, and the cost will also increase accordingly. The latter requires the addition of an overpolarized magnet section. The overpolarized magnet section used in the production metering magnetic resonance multiphase flowmeter 1 adopts a multi-ring magnet design, which adds a small magnet to the outside of the existing magnet ring to increase the magnetic field strength. However, this method has two problems: one is that it leads to an increase in the volume of the overpolarized section magnet and the overall volume of the probe. In addition, the size of the overpolarized magnet section magnet is different from that of the detection section, which requires separate mold processing, resulting in higher costs. To address this issue, this paper proposes a novel over-polarized magnet scheme. Specifically, the probe of the magnetic resonance multiphase flowmeter for oil and gas testing employs a multi-ring magnet structure, with each ring being identical. The magnetization length of the fluid is extended by setting the spacing between the rings. In this structure, there is no spacing between the magnet rings in the pre-polarized section, increasing the magnetic field strength, while spacing is reserved in the detection section. Because all magnet rings are completely identical, the manufacturing cost is low, and there is ample room for adjustment in the later stages. The magnet rings can use either toroidal magnets or Halbach magnet structures, without affecting the implementation of this design.

[0046] Figure 3 This is a flowchart of a multiphase flow metering method provided in one embodiment of the present invention. Figure 3 As shown, an embodiment of the present invention provides a multiphase flow metering method, the method comprising:

[0047] Step S10: Measure the phase parameters of the fluid according to the selected measurement requirements and the corresponding measurement method.

[0048] Specifically, this invention is used in the fields of oil and gas testing, so it mainly involves the detection of two phases: liquid and gas. Different detection methods are preset to meet different detection needs. The two most crucial detection needs are the detection of water content in fluids and gas phase measurement methods. These methods correspond to the characteristics of oil and gas reservoirs, verifying the correctness of reservoir understanding and interpretation, evaluating the reservoir development value, and determining the production operation system. For example, if water content detection is required in the liquid to be tested, the corresponding water content detection button will be triggered. If both measurement needs exist simultaneously, water content and gas phase measurements will be performed sequentially according to the requirements.

[0049] Step S20: Simultaneously acquire the reflected signals of the fluid using two measuring antennas.

[0050] Specifically, different detection methods are executed according to different detection requirements. For water content measurement, firstly, two antennas simultaneously transmit CPMG pulse sequences and collect echo trains. Preferably, the echo interval used in this step is as small as possible, preferably 200µs. Each pulse obtains one echo, and the echo trains corresponding to each measurement antenna are obtained according to the pulse sequence. Then, based on the time sequence, the two echo trains are fitted to obtain two corresponding fitted curves. Because the gas phase signal and solid phase signal will decay completely in a very short time, and the remaining signal all comes from the liquid phase, when collecting liquid phase water content, it is necessary to ensure that the signal all comes from the liquid phase, that is, the amplitude after a preset time needs to be selected as the judgment signal. This preset time needs to ensure that the gas phase signal and solid phase signal have decayed completely, so the signal needs to be greater than 1ms. Preferably, the amplitudes of the two fitted curves at 1ms are directly obtained, and the water content and oil content are obtained according to the ratio of these two amplitudes. Because according to the principle of nuclear magnetic resonance, we know that when H nuclei are the research object, the content of H protons in the sample is proportional to the signal amount. Macroscopically speaking, for the same sample, the more mass, the stronger the signal. This forms the basis of our quantitative research. Before the experiment, we only need to prepare some standard samples with known content and obtain the linear relationship between their content and signal intensity. When we obtain similar unknown samples, we measure their signal intensity under the same parameters and use the correspondence of the standard lines to accurately and quickly obtain the sample content. Corresponding to the research patterns of H nuclei, since we cannot obtain the number of H protons in oil and gas, the amount of water and oil in the fluid being tested can be used to calculate the water and oil content.

[0051] For gas phase measurement methods, the signal attenuation is very rapid, making it impossible to measure water content using the same method. Therefore, it is necessary to pre-calibrate the equipment. Pre-calibrated equipment scales include: hydrogen index scales for oil and natural gas, length scales for the two measuring antennas, and effective area length scales for the magnet structures at the front ends of the two measuring antennas. These pre-calibrated scales can serve as a standard rule for gas phase measurements.

[0052] When setting the hydrogen index calibration for oil, a sample of the fluid to be tested is taken on-site. Then, the first amplitude value M(0) of the echo train is measured using an on-site oil sample and a pure water sample of the same size. 油 and M(0) 水 The hydrogen content index (HI) of the oil is then obtained based on the calculated amplitude. 油 The calculation formula is as follows:

[0053]

[0054] There are several methods for presetting the hydrogen content index of natural gas, including:

[0055] 1) Collect fluid samples to be tested on site, and then measure the echo train amplitude M(0) of each sample using on-site oil and pure water samples of the same size. 油 and M(0) 水 Similar to the method for setting the hydrogen index of oil, the hydrogen index of natural gas is obtained. Because gas is greatly affected by temperature and pressure, the temperature and pressure parameters are adjusted within a preset range, and then the hydrogen index of natural gas under each temperature and pressure condition is obtained.

[0056] 2) On-site direct calibration: Apply full-pipe gas on-site, switch the valve to the stationary state, read the temperature and pressure data, measure the initial amplitude, and simultaneously measure the initial amplitude of full-pipe water. The calibration will display the hydrogen content index (HI) of pressurized natural gas. 气 .

[0057] 3) Direct calibration on-site; calibration at the production well (with a relatively fixed oil-gas-water ratio), valves switched to a static state, temperature and pressure data read, T2 spectrum measured, gas peak found, forward modeling obtained the first amplitude of the echo train, combined with the gas content provided by the oilfield, to derive the hydrogen content index HI of natural gas. 气 .

[0058] When setting the length scale of two measuring antennas, water with a known fixed flow rate is applied, and an approximate antenna length is set in the spectrometer software interface. Preferably, the nuclear magnetic resonance velocity is calculated by the echo train attenuation rate of the first 50ms acquired by the CPMG pulse sequence, and the set antenna length data is adjusted. When the measured flow rate matches the actual flow rate, the set antenna length data is the actual effective antenna length.

[0059] When setting the effective region length of the front-end magnet structure of the two measuring antennas, water with a fixed flow rate is applied, and the first amplitude value M(t) of the echo train of the two antennas is collected using the Flow mode of the spectrometer. A and M(t') B Then close the valve, cut off the valve power supply, and again use Flow mode to collect the first amplitude M(0) of the echo trains from the two antennas. A and M(0) B The time taken for the fluid to flow into the two antennas after entering the magnet and becoming magnetized is obtained using a preset relationship. The preset relationship is as follows:

[0060] M(t)=M(0)*(1-exp(-t / T1 水 ))

[0061] Then, by combining the given flow velocity, the effective region length scale of the magnet structure at the front end of the two measuring antennas can be calculated.

[0062] After completing the scale preset, the gas content measurement can be performed. First, since the fluid tube contains only liquid and natural gas, the following formula always holds true:

[0063] R 气 +R 液 =1

[0064] Among them, R 液 =R 水 +R 油 , represents the content ratio of the liquid phase; R 气 This represents the proportion of gas phase content. At this point, the first amplitude of the multiphase flow signal acquired by the main antenna is M. mix Its expression is:

[0065] M mix =R 气 *M 气 +R 液 *M 液

[0066] Among them, M mix M represents the initial amplitude of the measured multiphase flow signal. 气 The first amplitude value of the multiphase flow signal is marked by the hydrogen content index of natural gas; M 液 This is the initial amplitude of the signal when the pipe is filled with the current oil-water ratio liquid phase fluid. Its expression is:

[0067] M 液 =R 水 *M 水 +R 油 *M 油

[0068] =R 水 *M水 +(1-R 水 )*M 水 *HI 油

[0069] M 水 and M 油 These are the initial amplitude values ​​of the echo train signals when the pipe is full of oil and when it is completely full, respectively. Based on the above conversion relationship, the gas phase content ratio is obtained. However, the gas phase content ratio obtained here is the gas volume fraction under operating conditions and needs to be converted to the gas volume fraction under standard conditions based on the pipe temperature, pressure, and gas composition.

[0070] In one embodiment, the method further includes a flow velocity measurement method. During the oil and gas testing phases, the fluid flow rate is large and the flow velocity is fast, and due to the complex flow regime, a high measurement frequency is required. However, magnetic resonance signals are very weak (nV level) and easily drowned out by electronic noise. Therefore, magnetic resonance measurements often require repeated measurement and signal accumulation to obtain a higher signal-to-noise ratio. However, multiple accumulation tests mean longer single measurement times, which is obviously contradictory. Therefore, this invention proposes a flow velocity measurement method based on single accumulation of dual-antenna signals. First, two measuring antennas simultaneously transmit CPMG pulse sequences and acquire echo trains; the echo trains from the two measuring antennas are fitted to obtain two fitted curves; the amplitudes of the two fitted curves at preset times are extracted; and the water content and oil content of the current fluid are obtained based on the amplitude ratio of the two fitted curves at the same time.

[0071] Step S30: Read the phase parameters of the fluid based on the collected reflection signal and the preset device scale.

[0072] Specifically, based on the detection methods for different detection requirements mentioned in step S20, the corresponding detection signals are collected, and the required detection results are output based on the corresponding detection signals, thus realizing the concept of oil and gas testing using nuclear magnetic resonance technology.

[0073] The present invention also provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described multiphase flow metering method.

[0074] Those skilled in the art will understand that all or part of the steps in the methods of the above embodiments can be implemented by a program instructing related hardware. This program is stored in a storage medium and includes several instructions to cause a microcontroller, chip, or processor to execute all or part of the steps of the methods described in the various embodiments of the present invention. The aforementioned storage medium includes various media capable of storing program code, such as a USB flash drive, a portable hard drive, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disk.

[0075] The optional embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the embodiments of the present invention are not limited to the specific details described above. Within the scope of the technical concept of the embodiments of the present invention, various simple modifications can be made to the technical solutions of the embodiments of the present invention, and these simple modifications all fall within the protection scope of the embodiments of the present invention. It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the embodiments of the present invention will not further describe the various possible combinations.

[0076] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the embodiments of the present invention, they should also be regarded as the content disclosed by the embodiments of the present invention.

Claims

1. A multiphase flow metering system, characterized in that, The multiphase flow metering system includes: a magnetic resonance multiphase flow meter and a corresponding manifold system; wherein, The manifold system includes: a measurement trunk line and measurement branches; The measuring trunk is formed by connecting the following components in sequence: a first three-way valve (2), a two-way valve (3), a second three-way valve (4), and a third three-way valve (5); The magnetic resonance multiphase flow meter (1) is disposed between the two-way valve (3) and the second three-way valve (4); The measuring branch includes: a fourth three-way valve (6) and a pressure-limiting safety valve (7); The measuring branch is connected to the measuring main line via the third port of the first three-way valve (2), the third port of the second three-way valve (4), and the third port of the third three-way valve (5); The opening and closing states of the first three-way valve (2), the second three-way valve (4), the third three-way valve (5), and the fourth three-way valve (6) are determined by the fluid detection state; among them, If fluid is detected to be in a flowing state, then: the first three-way valve (2), the third three-way valve (5), and the fourth three-way valve (6) are in a three-way state; the second three-way valve (4) is in a horizontal two-way state; the two-way valve (3) is in an open state; and the pressure limiting safety valve (7) is in a closed state. If the fluid is detected to be in a static state, then: the first three-way valve (2), the third three-way valve (5) and the fourth three-way valve (6) are in a three-way state; the second three-way valve (4) is in a state where the outlet end connected to the magnetic resonance multiphase flow meter (1) is closed and the other two ends are open; The two-way valve (3) is in the closed state; the pressure limiting safety valve (7) is in the ready-to-activate state; wherein, the activation condition of the pressure limiting safety valve (7) is that the pressure in the connecting pipeline is greater than a preset threshold. The manifold system includes multiple control valves and connecting pipes for controlling the flow of the corresponding fluid through the magnetic resonance multiphase flow meter; The magnetic resonance multiphase flow meter includes a plurality of magnet structures spaced apart along the axial direction of the magnetic resonance multiphase flow meter for magnetizing the fluid; The magnetic resonance multiphase flowmeter also includes two measuring antennas spaced apart along the axial direction of the magnetic resonance multiphase flowmeter for detecting the phase state of the magnetized fluid.

2. The system according to claim 1, characterized in that, The rear half of the magnetic resonance multiphase flowmeter (1) along the axis is used as the detection section, and the front half of the magnetic resonance multiphase flowmeter (1) along the axis is used as the polarization section. The multiphase flow metering system also includes two measuring antennas; both measuring antennas are located in the detection section of the magnetic resonance multiphase flow meter (1).

3. The system according to claim 2, characterized in that, The magnet structure is a ring magnet structure or a Halbach magnet structure; The magnet structure contact connection arrangement is located in the polarization section of the magnetic resonance multiphase flowmeter (1); The magnet structures located in the detection section of the magnetic resonance multiphase flowmeter (1) are arranged at equal intervals.

4. A multiphase flow metering method, characterized in that, The method is implemented based on the multiphase flow metering system according to any one of claims 1-3, and the method includes: According to the selected measurement requirements, the phase parameters of the fluid are measured according to the corresponding measurement method; wherein, the phase parameters are the content parameters or velocity parameters of the target phase. The reflected signals of the fluid are acquired simultaneously using two measuring antennas; The phase parameters of the fluid are read based on the collected reflected signals and the preset device scale.

5. The method according to claim 4, characterized in that, The measurement method includes: Methods for measuring moisture content, gas phase measurement, and flow velocity measurement.

6. The method according to claim 5, characterized in that, The moisture content measurement method includes: Collect echo trains of CPMG pulse sequences simultaneously transmitted by two measurement antennas; The echo trains of the two measurement antennas were fitted separately to obtain the corresponding fitting curves; Extract the amplitudes of the two fitted curves at preset times respectively; The water content and oil content of the current fluid are obtained by comparing the amplitude ratio of the two fitted curves at the same time.

7. The method according to claim 5, characterized in that, The preset device scale includes: The scale includes the hydrogen content index of oil, the hydrogen content index of natural gas, the length scale of the two measuring antennas, and the effective area length scale of the magnet structure at the front end of the two measuring antennas.

8. The method according to claim 7, characterized in that, The method further includes: Establish preset equipment calibrations, including establishing hydrogen content indexes for oil and natural gas; among which, The hydrogen content index of the constructed oil includes: Collect fluid samples, obtain the water content and oil content of the fluid samples, and obtain the hydrogen content index scale of the oil in the fluid samples based on the water content and oil content of the fluid samples; The construction of the hydrogen index scale for natural gas includes: Measure the water content and oil content of fluid samples at different temperatures and pressures, and obtain the hydrogen index scale of the natural gas in the test sample based on the water content and oil content of the fluid samples at different temperatures and pressures; or Fill the magnetic resonance multiphase flow meter (1) with fluid sample and water respectively. Under the condition that the fluid is in a static state, obtain the first measurement value of the fluid sample and the first measurement value of the water respectively. Obtain the hydrogen content index scale of natural gas based on the ratio of the two.

9. The method according to claim 8, characterized in that, The gas phase measurement method includes: Obtain the first amplitude value of the multiphase flow signal acquired by any measurement antenna; The gas phase content ratio is obtained based on the initial amplitude value of the multiphase flow signal and a preset conversion relationship between the initial amplitude value and the gas phase content ratio. The conversion relationship is as follows: Among them, M mix This represents the initial amplitude of the measured multiphase flow signal. This represents the proportion of gas phase content. The first amplitude value of the multiphase flow signal is marked by the hydrogen content index scale of natural gas; R 液 =R 水 +R 油 , which represents the content ratio of the liquid phase; M 液 This is the initial signal amplitude when the connecting pipe is filled with liquid phase fluid of the current oil-to-water ratio. M 水 This is the initial signal amplitude when the connecting pipe is filled with oil. This is the hydrogen index scale for oil; The gas volume fraction under standard operating conditions is obtained based on the gas phase content ratio, and the obtained gas volume fraction is used as the gas phase measurement result.

10. The method according to claim 5, characterized in that, Prior to performing the flow velocity measurement method, the method further includes: The echo train data from the two measurement antennas are superimposed, including: Extract echo train data measured by two measurement antennas; wherein the CPMG pulse sequences used by the two measurement antennas have the same number of pulses and echo interval, and the phase difference is 180°; Multiply all echo data from one of the measuring antennas by the wavenumber of the echo to obtain the processed echo data from that antenna. Then, sum the processed echo data from the measuring antenna with the echo data from the other measuring antenna, and measure the fluid velocity based on the summed echo data.

11. A computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the multiphase flow metering method according to any one of claims 4-10.

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