Downhole two-phase flow sensor nipple based on optical fiber sensing and design and measurement method

Abstract

The invention provides an underground two-phase flow sensor pup joint based on optical fiber sensing and a design measuring method.The underground two-phase flow sensor pup joint based on optical fiber sensing comprises a pup joint inner pipe, a pup joint outer pipe, a fiber coiling cover, a fiber coiling sleeve and a winding optical fiber, and the winding optical fiber is wound on the pup joint inner pipe; the short section inner pipe is connected with the short section outer pipe, the fiber coiling sleeve is connected with the short section outer pipe through welding, and the fiber coiling cover is welded on the fiber coiling sleeve. According to the down-hole two-phase flow sensor short section based on optical fiber sensing and the design and measurement method, the down-hole two-phase flow sensing short section which is high in reliability and simple in structure and is used for distributed optical fiber sensing is designed, down-hole flow detection is achieved, and it is guaranteed that the flow has the long service life and the accuracy of detection in a severe environment.

Description

Technical Field

[0001] The invention relates to the technical field of pipeline two-phase flow testing, and in particular to an optical fiber sensing-based downhole two-phase flow sensor pup joint and a design and measurement method. Background Art

[0002] The product obtained from oil extraction is a ternary two-phase mixture of oil, gas and water. The measurement parameters such as the flow rate and proportion of each phase help engineers evaluate the oil reserves and distribution in the subsurface oil layer, so as to locate and control the oil layer in time, adjust and optimize the oil and gas field development plan, arrange production reasonably, extend the life of the oil well, and improve the crude oil recovery rate. Unlike unidirectional flow, the different physical and chemical properties of each phase in the multiphase flow system make its flow characteristics relatively complex, changeable and have strong uncertainty. Therefore, the accurate measurement of multiphase flow parameters is still a difficult topic.

[0003] By searching public technical reports, academic papers, invention patents and other literature, it is found that the traditional oil field measurement method for obtaining multiphase flow parameters usually uses a three-phase separator to separate oil, gas and water, or a two-phase separator to separate the gas and liquid phases, and then measures them separately. In the Chinese patent application with application number: 201720697433.6, a single-well multiphase flow metering device is involved, including a gas-liquid separation tank, a gas phase pipeline, and a liquid phase pipeline. The inlet of the gas-liquid separation tank is connected to the wellhead of the oil well, the upper end of the gas-liquid separation tank is provided with a gas phase outlet, and the lower end is provided with a liquid phase outlet. The interior of the gas-liquid separation tank is provided with a collision plate at the inlet to perform collision separation on the gas-liquid mixture; the gas enters the mixed transportation pipeline through the gas phase pipeline, and the liquid enters the mixed transportation pipeline through the liquid phase pipeline. The pump on the liquid phase pipeline can form a low pressure in the gas-liquid separation tank, which is conducive to gas-liquid separation. A water content analyzer and a mass flow meter are successively arranged between the liquid phase outlet and the pump. The water content analyzer is used to detect the water content, and the mass flow meter can measure the flow and density of the mixed liquid, and calculate the flow of each phase in the mixed liquid according to the density of the heavy oil and the thin oil itself; the combination of the collision separation method and the low-pressure separation method makes the gas-liquid separation more thorough, so the measurement result is more accurate. The separation equipment is complex, occupies a large area, is costly, and requires a long time to separate the oil, gas and water mixture. It has defects such as long time consumption and large hysteresis, and cannot achieve continuous single-well measurement.

[0004] At present, the existing non-separation detection of multiphase flow parameters mostly adopts a method of combining a flow meter with a water content sensor. In the Chinese patent application with application number: 201320859265.8, an integrated device for online measurement of the flow rates of oil, water and gas in a multiphase flow is disclosed, which comprises the following components: a venturi flow meter (3); a first dual-energy gamma ray phase analyzer (2) arranged at the inlet or throat of the venturi flow meter (3); an online liquid sampling device (4) arranged downstream of the venturi flow meter, which comprises: an inlet pipe (4-1), a swirl chamber (4-2), a collision chamber (4-4), a gas outlet pipe (4-5) and a liquid outlet pipe (4-6). The invention relates to a method for preparing a liquid gas discharge pipe (4-3), wherein one end of the inlet pipe is connected to the venturi tube, and the other end is tangentially connected to the cyclone chamber, a collision chamber is arranged above the cyclone chamber, and at least one layer of screen is arranged in the collision chamber, the gas outlet pipe is located at the top of the collision chamber, and the liquid outlet pipe is located on the side wall of the bottom of the cyclone chamber, and bends upward after leaving the cyclone chamber to form a liquid outlet pipe including a section of vertical pipe; a second dual-energy gamma ray phase fractionator (5) arranged at the vertical pipe; a data acquisition and processing system (6); a gas-liquid re-merging pipe (7); wherein the venturi tube flowmeter (3), the online liquid sampling device (4) and the gas-liquid re-merging pipe (7) are made into an integrated structure. The method adopts a method of combining a venturi tube flowmeter with a gamma ray phase resolution instrument, using a venturi tube to measure the flow rate and using gamma rays to obtain the phase content of each phase, but this method is not suitable for the healthy development of industry because it uses radioactive rays, which causes great environmental pollution.

[0005] In order to avoid environmental pollution, a multiphase flow fluid measurement system is involved in the Chinese patent application with application number: 202110668722.4. The existing oil, gas and water three-phase flowmeter is harmful to the environment and human body to a certain extent, and the later cost is relatively high. The application provides a multiphase flow fluid measurement system, including a flowmeter module, a water content module and a data acquisition and processing module, wherein the flowmeter module is connected to the water content module, the flowmeter module is connected to the data acquisition and processing module, and the water content module is connected to the data acquisition and processing module; the flowmeter module is used to measure the virtual high flow of the fluid; the water content module is used to measure the phase content of water; the data acquisition and processing module is used to collect data and calculate the flow of each phase. The modular design of the sensor facilitates the adjustment of the sensor position according to different metering requirements, and can provide fast, stable and reliable metering detection results for oil and gas wells under different working conditions. The invention proposes a method of combining a venturi tube with a microwave sensor. By collecting the Venturi pressure difference signal and the microwave amplitude and phase signal, the gas and liquid two-phase flow of the wetland can be detected. It is different from the principle described in this patent.

[0006] With the development of computer technology, a multiphase flow detection method and system are involved in the Chinese patent application with application number: 202110367036.3. The accuracy of the venturi tube in measuring oil and gas multiphase flow with high gas content is relatively limited, and other sensors are required for auxiliary measurement. Capacitance tomography can measure the flow pattern and cross-sectional gas content of oil and gas multiphase flow, but it can only provide information on the fluid cross section, and it is difficult to provide real-time available information for the traditional semi-empirical measurement model of the venturi tube. The application provides a multiphase flow detection method, which includes the following steps: 1) collecting the flow signal of the multiphase flow; 2) obtaining a large number of multiphase flow data samples to train the deep learning model; 3) inputting the flow signal into the deep learning model to obtain the flow rate of each phase in the multiphase flow. The method based on the venturi tube and ECT combined with deep learning can measure the oil phase flow and gas phase flow in the oil and gas multiphase flow online, and improve its measurement accuracy. However, it requires a large number of multiphase flow data samples for training, a large number of data sets, and increased preliminary work preparation.

[0007] With the development of multiphase flow software, virtual flow meters have been generated and developed. In the Chinese patent application with application number: 202210799639.5, a virtual metering system for oil and gas two-phase flow is involved, which is mainly composed of three parts: a flow parameter measurement sensor system, a mobile metering vehicle, and a central processor. The invention combines a large amount of low-fidelity data from the multiphase flow software with a small amount of high-fidelity data measured by the metering vehicle, and establishes a mapping relationship between low-fidelity data and high-fidelity data through a multi-layer neural network, thereby migrating low-fidelity data to high-fidelity data. Real-time and accurate flow can be obtained by installing sensors such as starting pressure, starting temperature, throttling differential pressure, pipeline pressure drop, and pipeline temperature drop on the pipeline. This method has the advantages of low cost and high measurement accuracy, but due to the complexity of the downhole environment and the ever-changing variables, the parameter setting of the virtual flowmeter becomes very complicated. The sensors used in the above multiphase flow measurement methods have a common disadvantage: they cannot have good reliability and long-term stability in oil and gas wells with extremely harsh environments such as high temperature, high pressure, corrosion, strong electromagnetic interference, and narrow space. Therefore, it is urgent to develop a reliable and low-cost flow measurement system that can realize online, non-separation measurement of single-well multiphase flow.

[0008] The above existing technologies are greatly different from the present invention and fail to solve the technical problem we want to solve. For this reason, we have invented a new downhole two-phase flow sensor pup joint based on optical fiber sensing and a design and measurement method. Summary of the invention

[0009] The purpose of the present invention is to provide a downhole two-phase flow sensor pup joint based on optical fiber sensing and a design and measurement method thereof, which can realize the measurement of oil-water or gas-water two-phase flow and phase content in a production layer.

[0010] The object of the present invention can be achieved through the following technical measures: a downhole two-phase flow sensor pup section based on optical fiber sensing, the downhole two-phase flow sensor pup section based on optical fiber sensing includes a pup section inner tube, a pup section outer tube, a fiber coil cover, a fiber coil sleeve and a wound optical fiber, the wound optical fiber is wound on the pup section inner tube, the pup section inner tube is connected to the pup section outer tube, the fiber coil sleeve is connected to the pup section outer tube by welding, and the fiber coil cover is welded to the fiber coil sleeve.

[0011] The purpose of the present invention can also be achieved by the following technical measures:

[0012] The downhole two-phase flow sensor pup joint based on optical fiber sensing also includes a pup joint sleeve, which is connected to the pup joint outer tube through screws and is equipped with a sealing ring.

[0013] The downhole two-phase flow sensor pup joint based on optical fiber sensing also includes a sealing gasket. The pup joint inner tube and the pup joint outer tube are connected by screws, positioned by the axle shoulder of the pup joint inner tube, and sealed with the sealing gasket.

[0014] The fiber coil cover is provided with small holes and equipped with fasteners to facilitate the passage, fastening and sealing of the wound optical fiber.

[0015] When the wound optical fiber is wound around the short section inner tube, it is divided into a tightly wound section and an interval wound section.

[0016] The optical cable outside the short section of the downhole two-phase flow sensor based on optical fiber sensing is a stainless steel armored oil well optical cable, which is fused with the wound optical fiber for well-to-ground optical signal transmission.

[0017] The two ends of the inner tube of the short section are connected to the oil pipe through an oil pipe coupling, and the fiber coil sleeve is connected to the inner tube of the short section through a thread.

[0018] The purpose of the present invention can also be achieved by the following technical measures: a downhole two-phase flow sensor pup joint design and measurement method based on optical fiber sensing, the downhole two-phase flow sensor pup joint design and measurement method based on optical fiber sensing adopts a downhole two-phase flow sensor pup joint based on optical fiber sensing, including:

[0019] Step 1, winding the wound optical fiber on the inner tube of the short section of the downhole two-phase flow sensor short section based on optical fiber sensing, which is divided into a tightly wound section and an interval wound section;

[0020] Step 2: Connect the downhole two-phase flow sensor sub based on optical fiber sensing to the distributed acoustic sensor demodulation device, and the distributed acoustic sensor demodulation device is connected to the host computer data processing system;

[0021] Step 3, lowering a downhole two-phase flow sensor sub based on optical fiber sensing into the wellbore;

[0022] Step 4, fix the optical cable to the outer wall of the oil pipe by using an optical cable fixing centralizer, so that the optical cable and the downhole two-phase flow sensor short section based on optical fiber sensing are located at the upper part of the oil layer;

[0023] Step 5: When the fluid passes through the downhole two-phase flow sensor pup joint based on optical fiber sensing, it will impact the pipe wall and cause the pipeline to vibrate laterally. The vibration signal is sensed through the optical fiber and transmitted to the ground data processing system through the optical cable for data collection.

[0024] Step 6, performing a two-dimensional Fourier transform on the signal data of the interval winding section to obtain a frequency wavenumber spectrum;

[0025] Step 7, average the signal data of the tightly wound section over the distance, take the tightly wound section of the optical fiber as a vibration measurement point, make the standard deviation STD of the vibration measurement point signal, substitute the STD and the mixed flow rate under the oil or water content into the fitting relationship, and calculate the pipeline mixed flow rate.

[0026] The purpose of the present invention can also be achieved by the following technical measures:

[0027] In step 1, a prestress T0 is given to the wound optical fiber to ensure the strain coupling efficiency between the optical fiber and the short section; the interval winding section of the optical fiber has a long winding distance, which corresponds to a long distance of sound transmission in the fluid; because the speed of sound transmission in different media is different, the speed of sound propagation in the fluid can be detected, and the phase content can be measured corresponding to the sound velocity diagram of different phase volume fractions.

[0028] In step 1, a two-dimensional Fourier transform is performed on the spatiotemporal data collected by the interval-wound optical fiber to obtain a frequency wavenumber spectrum, and then two oblique lines are obtained on the frequency wavenumber spectrum through a fitting algorithm. The formula It can be seen that the slope of the oblique line represents the speed of sound wave propagation in the medium; the slopes of the two oblique lines on the frequency wave number diagram represent the upward speed of sound C and u and downlink speed C d , and according to the Doppler effect, the static sound speed V = (C u +C d ) / twenty two).

[0029] In step 1, there is a monotonically decreasing relationship between the sound velocity of the oil-water two-phase and the phase content, that is, when the oil content increases, the sound velocity decreases, and when the water content increases, the sound velocity increases; this relationship can be fitted with a cubic function to obtain a better fitting effect; therefore, it is only necessary to obtain the static sound velocity v from the collected signal, and the oil or water content can be calculated by the fitting formula; the optical fiber in the tightly wound section is densely arranged and the winding section is short, so it is considered that the vibration signal in this section is consistent; the pipeline filled with liquid is simplified into a one-dimensional beam model, and combined with the beam deflection equation, the pipeline acceleration and pressure fluctuation can be established Relationship: The pressure fluctuation p′ is proportional to the fluctuation of the fluid velocity, i.e., the axial velocity u′ and the radial velocity v′

[0030] In step 1, the tightly wound section of the optical fiber is used as a vibration measurement point, and the standard deviation STD of the vibration measurement point signal is calculated. In theory, there is a quadratic linear relationship between the standard deviation of the pipeline flow-induced vibration signal and the flow rate in the pipe. Before using the downhole two-phase flow sensor pup joint based on optical fiber sensing, it is necessary to calibrate the fitting relationship between the static sound velocity and the oil or water content, as well as the fitting relationship between the STD and the mixed flow at various oil or water content in the oil-water circulation flow test platform.

[0031] In step 3, one end of the fiber optic sensing downhole two-phase flow sensor short section is connected to the oil pipe, and the other end is connected to the dispenser or the oil pump. According to the engineering test requirements, the sensor short section is connected to the appropriate position of the oil pipe and lowered into the wellbore.

[0032] In step 6, the static sound velocity is calculated using formulas (1) and (2), and the static sound velocity is substituted into the fitting relationship between the static sound velocity and the oil or water content to calculate the oil or water content.

[0033] In step 4, the vertical well downhole fluid production profile flow monitoring system only requires a downhole two-phase flow sensor pup joint based on optical fiber sensing, which is located in the upper part of the oil layer.

[0034] In step 4, the horizontal well downhole fluid production profile flow monitoring system requires multiple downhole two-phase flow sensor short sections based on optical fiber sensing, which are distributed in the horizontal oil layer.

[0035] In step 4, the vertical well downhole steam injection flow rate and liquid production profile measurement system requires a downhole two-phase flow sensor short section based on optical fiber sensing, which is located on the upper part of the injector.

[0036] In step 4, the horizontal well downhole steam injection flow rate and liquid production profile measurement system requires multiple downhole two-phase flow sensor short sections based on optical fiber sensing, distributed in the horizontal oil layer, and requires an injection dispenser.

[0037] The present invention provides a downhole two-phase flow sensor subsection based on optical fiber sensing and a design and measurement method, and designs a downhole two-phase flow sensor subsection with high reliability and simple structure based on distributed optical fiber sensing, which not only realizes the detection of downhole flow, but also ensures that the flow has a long service life and the accuracy of detection in harsh environments. Compared with the prior art, the present invention has the following beneficial effects:

[0038] 1. The present invention has found through experiments that under a fixed phase content, there is a fixed quadratic linear relationship between the vibration signal STD and the pipeline flow rate.

[0039] 2. The present invention has found through experiments that there is a monotonic correspondence between the oil-water two-phase content and the static sound velocity.

[0040] 3. To ensure efficient coupling between the optical fiber and the short section wall, it is necessary to wrap it with bare optical fiber and keep the winding prestress uniform.

[0041] 4. The sensor nipple uses sealing structures such as sealing rings and screws to ensure the reliability of the sensor in the underground environment. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] Figure 1 It is a schematic diagram of a downhole production fluid profile flow monitoring system for a vertical well in a specific embodiment of the present invention;

[0043] Figure 2 It is a schematic diagram of a downhole production profile flow monitoring system for a horizontal well in a specific embodiment of the present invention;

[0044] Figure 3 It is a schematic diagram of a downhole steam injection flow and liquid production profile monitoring system for a vertical well in a specific embodiment of the present invention;

[0045] Figure 4 It is a schematic diagram of a downhole steam injection flow rate and liquid production profile monitoring system for a horizontal well in a specific embodiment of the present invention;

[0046] Figure 5 It is a schematic diagram of the internal structure of a sensor short section in a specific embodiment of the present invention;

[0047] Figure 6 It is a schematic diagram of the frequency wavenumber spectrum of the interval winding segment data after two-dimensional Fourier transformation in a specific embodiment of the present invention;

[0048] Figure 7 is a fitting relationship diagram between the oil-water two-phase sound velocity and the phase holdup obtained by experiment in a specific embodiment of the present invention;

[0049] Figure 8 It is a fitting relationship diagram of the vibration signal STD and flow rate at a certain oil-water two-phase content measured experimentally in a specific embodiment of the present invention;

[0050] In the figure, 1-sensor short section; 2-stainless steel armored optical cable; 3-oil pipe; 4-optical cable fixing and straightening device; 5-distributed acoustic sensor demodulation equipment; 6-data processing system; 7-injection device; 8-oil layer; 9-packer; 10-oil pump; 11-stainless steel armored optical cable; 12-optical cable fastener; 13-fiber coiling cover; 14-fiber coiling sleeve; 15-optical fiber fusion point; 16-sealing gasket; 17-bare optical fiber tightly wound section; 18-bare optical fiber interval winding section; 19-short section outer tube; 20-screw; 21-short section sleeve; 22-short section inner tube; 23-oil pipe coupling. DETAILED DESCRIPTION

[0051] It should be noted that the following detailed descriptions are exemplary and are intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meanings as those commonly understood by those skilled in the art to which the present invention belongs.

[0052] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, it indicates the presence of features, steps, operations and / or combinations thereof.

[0053] In the past decade, fiber optic sensing technology has developed rapidly. Fiber optic sensing technology uses light waves as information carriers and optical fibers as transmission media to sense changes in external physical quantities. When light waves are transmitted in optical fibers, their power, phase, wavelength, polarization state and other parameters will change due to the influence of the external environment. By detecting the changes in the parameters of the light waves transmitted in the optical fiber, the measured information of the external environment can be obtained. Fiber optic sensing technology has become an emerging oil well detection technology due to its high efficiency, resistance to high pressure and high temperature, and immunity to electromagnetic interference.

[0054] Distributed fiber optic acoustic sensing technology detects signals such as sound or vibration within the audio range based on the phase of coherent Rayleigh scattered light, and uses the phase amplitude to quantitatively obtain the intensity information of the sound or vibration event. Indoor experimental studies have shown that when a two-phase mixed fluid passes through a pipeline, it will cause the pipe wall to vibrate laterally, and the vibration intensity is quadratically related to the mixed flow rate, and the speed of sound propagating on the pipe wall is monotonically related to the water content. Therefore, the measurement of two-phase flow can be achieved through the special winding method of the optical fiber on the pipeline and the corresponding interpretation algorithm. Based on this technical feature, the present invention designs a downhole two-phase flow sensor short section with high reliability and simple structure for distributed fiber optic sensing. Not only does it realize the detection of downhole flow, but it also ensures that the flow has a long service life and the accuracy of detection in harsh environments.

[0055] The present invention designs a downhole two-phase flow sensor pup joint based on optical fiber sensing to ensure good sealing performance and high reliability. The sensor is mainly composed of an inner and outer tube of the pup joint, a fiber coil cover, a fiber coil sleeve, a pup joint sleeve and a wound optical fiber. The inner and outer tubes of the pup joint are connected by bolts, positioned by the shaft shoulder of the inner tube of the pup joint, and sealed with a sealing gasket to prevent the fluid outside the pup joint from entering. The fiber coil sleeve is connected to the outer tube of the pup joint by welding. The fiber coil cover is connected to the fiber coil sleeve by laser welding, and a small hole is provided on the cover and fasteners are provided for the passage of the optical cable, the optical cable is fastened and sealed. The bare optical fiber is wound inside the pup joint, which is divided into a tightly wound section and an interval wound section. The optical cable outside the pup joint is a stainless steel armored oil well optical cable, which is fused with the bare optical fiber inside the pup joint for well-ground optical signal transmission. The pup joint sleeve is connected to the outer tube by screws and is equipped with a sealing ring. The various parts of the sensor pup joint are reliably connected and well sealed, and the optical fiber is used as a sensing element, which has high reliability and good life and is not affected by the harsh environment of the well.

[0056] The design and measurement method of the downhole two-phase flow sensor pup joint based on optical fiber sensing in the present invention includes:

[0057] Step 1: Wrap the bare optical fiber on the inner tube of the sensor short section, which is divided into a tightly wound section and an interval wound section, and give prestress T0 at the same time to ensure the strain coupling efficiency between the optical fiber and the short section. The interval wound section of the optical fiber has a long winding distance, which corresponds to a long distance of sound transmission in the fluid. Since the speed of sound transmission in different media is different, the speed of sound propagation in the fluid can be detected, and the phase content can be measured corresponding to the sound velocity diagram of different phase volume fractions. Perform a two-dimensional Fourier transform on the spatiotemporal data collected by the interval wound optical fiber to obtain a frequency wavenumber spectrum, and then use the fitting algorithm to obtain two oblique lines on the frequency wavenumber diagram. According to the formula It can be seen that the slope of the oblique line represents the speed of sound wave propagation in the medium. The slopes of the two oblique lines on the frequency wave number diagram represent the upward speed of sound C u and downlink speed C d , and according to the Doppler effect, the static sound speed V = (C u +C d ) / 2 (2). Figure 7 It can be seen that there is a monotonically decreasing relationship between the sound velocity of the oil-water two-phase and the phase content, that is, when the oil content increases, the sound velocity decreases, and when the water content increases, the sound velocity increases. This relationship can be fitted with a cubic function to obtain a better fitting effect. Therefore, it is only necessary to obtain the static sound velocity v from the collected signal, and the oil (or water) content can be calculated by the fitting formula. The optical fiber in the tightly wound section is densely arranged and the winding section is short, so it is considered that the vibration signal in this section is consistent. The liquid-filled pipeline is simplified into a one-dimensional beam model, and combined with the beam deflection equation, the pipeline acceleration and pressure fluctuation can be established. Relationship. Pressure fluctuation p' is proportional to the fluctuation of fluid velocity (axial velocity u' and radial velocity v') Therefore, the tightly wound section of the optical fiber is used as a vibration measurement point, and the standard deviation (STD) of the vibration measurement point signal is calculated. In theory, there is a quadratic linear relationship between the standard deviation of the pipeline flow-induced vibration signal and the flow rate in the pipe. Before using the sensor nipple 1, it is necessary to calibrate the fitting relationship between the static sound velocity and the oil (or water) content and the fitting relationship between the STD and the mixed flow at each oil (or water) content in the oil-water circulation flow test platform.

[0058] Step 2: Connect the two-phase flow sensor short section to the distributed acoustic sensor demodulation device through the stainless steel armored optical cable, and the distributed acoustic sensor demodulation device is connected to the host computer data processing system.

[0059] Step 3: Connect one end of the sensor nipple to the tubing and the other end to the dispenser or oil pump. Connect the sensor nipple to the appropriate position of the tubing according to the engineering test requirements and lower it into the wellbore.

[0060] Step 4: Fix the optical cable to the outer wall of the oil pipe through the optical cable fixing stabilizer so that the optical cable and the sensor short section are located above the oil layer.

[0061] Step 5: When the fluid passes through the sensor nipple, it impacts the pipe wall and causes lateral vibration of the pipeline. The vibration signal is sensed through the optical fiber and transmitted to the ground data processing system through the optical cable for data collection.

[0062] Step 6: Perform a two-dimensional Fourier transform on the signal data of the interval winding section to obtain a frequency wavenumber spectrum, calculate the static sound velocity using formulas (1) and (2), substitute it into the fitting relationship between the static sound velocity and the oil (or water) content, and calculate the oil (or water) content.

[0063] Step 7: Average the signal data of the tightly wound section over the distance, take the tightly wound section of the optical fiber as a vibration measurement point, make the standard deviation (STD) of the vibration measurement point signal, substitute it into the fitting relationship between STD and mixed flow under the oil (or water) content, and calculate the pipeline mixed flow.

[0064] The difference in measurement methods for different types of wells (such as vertical wells, horizontal wells, stratified steam injection wells, etc.) is mainly in the location and number of sensor subs 1, and the other steps are basically the same. Specifically:

[0065] 1. The vertical well downhole production profile flow monitoring system only needs one sensor short section 1, which is located at the upper part of the oil layer.

[0066] 2. The horizontal well downhole production profile flow monitoring system requires multiple sensor pup joints 1 distributed in the horizontal oil layer.

[0067] 3. The vertical well downhole steam injection flow and liquid production profile measurement system requires a sensor nipple located on the upper part of the injector.

[0068] 4. The downhole steam injection flow and liquid production profile measurement system for horizontal wells requires multiple sensor pup joints distributed in the horizontal oil layer and an injection device.

[0069] The present invention proposes a method for measuring the flow rate of two-phase flow in a downhole using distributed optical fiber sensing, that is, the standard deviation of the measured data corresponds to the flow rate, and the slope on the frequency wave number diagram corresponds to the phase content. During operation, the sensor short section is connected to the distributed acoustic sensor demodulation device through an optical cable, and the distributed acoustic sensor demodulation device is connected to the host computer data processing system. When the fluid passes through the sensor short section, it will impact the pipe wall and cause the pipeline to vibrate laterally, and the vibration signal is sensed by the optical fiber of the wound section of the short section body.

[0070] The optical fiber in the tightly wound section is densely arranged and the winding section is short, so it is considered that the vibration signal in this section is consistent. The pipeline filled with liquid is simplified into a one-dimensional beam model. Combined with the beam deflection equation, the following relationship between pipeline acceleration and pressure fluctuation can be established:

[0071]

[0072] The pressure fluctuation p′ is proportional to the fluctuation of fluid velocity (axial velocity u′ and radial velocity v′)

[0073]

[0074] It can be concluded that the lateral vibration acceleration of the pipeline has a certain relationship with the average flow rate. The upper computer extracts the signal data of this section and averages it over the distance. The tightly wound section of the optical fiber is used as a vibration measurement point, and the standard deviation (STD) of the vibration measurement point signal is calculated. In theory, there is a quadratic linear relationship between the standard deviation of the pipeline flow-induced vibration signal and the flow rate in the pipe. This relationship can be calibrated through experiments, thereby realizing the measurement of downhole flow.

[0075] For the interval-wound optical fiber, the winding distance is long, which corresponds to the long distance that the sound is transmitted in the fluid. Since the speed of sound transmission in different media is different, the speed of sound propagation in the fluid can be detected, and the phase content can be measured corresponding to the sound velocity diagram of different phase volume fractions. A two-dimensional Fourier transform is performed on the spatiotemporal data collected by the interval-wound optical fiber to obtain a frequency wavenumber spectrum. Then, two oblique lines are obtained on the frequency wavenumber diagram through a fitting algorithm. From formula (7), it can be seen that the slope of the oblique line represents the speed of sound wave propagation in the medium. From the Doppler effect, it can be seen that when the (sound source) flow moves relative to the position of the optical fiber, it measures the change in the frequency of the wave. From formula (8), it can be seen that the slopes of the two oblique lines on the frequency wavenumber diagram represent the upward speed of sound, C, and C, respectively. u and downlink speed Cd , static sound speed V = (C u +C d ) / 2 has a corresponding relationship with the phase content.

[0076]

[0077] Among them C m represents the multiphase sound velocity, while λ, f, and k represent the wavelength, frequency, and wave number, respectively.

[0078] V=(C u +C d ) / 2 (8)

[0079] Where V is the flow rate.

[0080] The following are several specific embodiments of the present invention.

[0081] Example 1: Downhole two-phase flow rate and liquid production profile measurement system

[0082] like Figure 1 As shown, it is a vertical well downhole production profile flow monitoring system, which is mainly a downhole flow measurement system based on distributed optical fiber sensing, including a two-phase flow sensor short section 1, a stainless steel armored optical cable 2, an oil pipe 3, an optical cable fixing and straightening device 4, a distributed acoustic sensor demodulation device 5 and a data processing system 6 connected in sequence. Before going down the well, the lower end of the sensor short section 1 is connected to the oil pipe 3, the upper end of the sensor short section 1 is connected to the oil pipe 3, and the optical cable 2 is fixed to the outer wall of the oil pipe 3 through the optical cable fixing and straightening device 4. The optical cable 2 passes through the ground through the wellhead and is connected to the distributed acoustic sensor demodulation device 5, which is connected to the host computer data processing system 6. Gently tap the two optical cable outlets of the short section, record the optical fiber length displayed in the host computer, and connect the sensor short section 1 to the appropriate position of the oil pipe 3 according to the engineering test requirements. After the measurement system is lowered according to the engineering design requirements, the fiber optic signal test is carried out. When the entire test system is working normally, the fiber optic data collection is started, and the collected fiber optic test data is transmitted to the ground through the data processing system 6 for data collection. The data collected by the data processing system 6 is processed to obtain the actual fluid production profile in the well.

[0083] like Figure 2As shown, it is a horizontal well downhole liquid production profile flow monitoring system, which is mainly a downhole flow measurement system based on distributed optical fiber sensing, including a two-phase flow sensor short section 1, a stainless steel armored optical cable 2, an oil pipe 3, an optical cable fixing and straightening device 4, a distributed acoustic sensor demodulation device 5 and a data processing system 6 connected in sequence. Before going down the well, the lower end of the sensor short section 1 is connected to the oil pipe 3, the upper end of the sensor short section 1 is connected to the oil pipe 3, and the optical cable 2 is fixed to the outer wall of the oil pipe 3 through the optical cable fixing and straightening device 4. The optical cable 2 passes through the wellhead and goes out of the ground, and is connected to the distributed acoustic sensor demodulation device 5, which is connected to the host computer data processing system 6. Gently tap the two optical cable outlets of the short section, record the optical fiber length displayed in the host computer, and connect the sensor short section 1 to the appropriate position of the oil pipe 3 according to the engineering test requirements. After the measurement system is lowered according to the engineering design requirements, the fiber optic signal test is carried out. When the entire test system is working normally, the fiber optic data collection is started, and the collected fiber optic test data is transmitted to the ground through the data processing system 6 for data collection. The data collected by the data processing system 6 is processed to obtain the actual fluid production profile in the well.

[0084] Example 2: Downhole steam injection flow and liquid production profile measurement system

[0085] like Figure 3 As shown, it is a downhole steam injection flow rate and liquid production profile measurement system for a vertical well. The system is mainly a downhole steam injection flow rate and liquid production profile measurement system based on distributed optical fiber sensing, including a two-phase flow sensor short section 1, a stainless steel armored optical cable 2, an oil pipe 3, an optical cable fixing and straightening device 4, a distributed acoustic sensor demodulation device 5, a data processing system 6, a dispenser 7, a packer 9, and a pump 10 connected in sequence. On the ground, the distributed acoustic sensor demodulation device 5 and the data processing system 6 are mainly connected to the optical cable 2, which is lowered into the wellbore through the wellhead. The optical cable 2 is fixed to the outside of the pump 10 and the oil pipe 3 through the optical cable straightening device 4. The optical cable 2 passes through the packer 9 through the traverser until it is lowered into the upper part of the oil layer 8. The sensor short section 1 and the optical cable 2 are located in the upper part of the oil layer 8. The bottom of the sensor short section 1 is connected to the dispenser 7 through the oil pipe 3, and the dispenser 7 is lowered to the engineering design position. The collected data signal is transmitted back to the optical fiber signal data processing system 6 on the ground through the optical fiber cable 2 for collection and processing.

[0086] When steam is injected into the production well, the measurement system measures the actual injection volume of the injector 7 through the sensor nipple 1. The sensor nipple 1 transmits the signal to the ground data processing system 6 through the optical cable 2 for data collection. The data collected by the data processing system 6 is processed to calculate the actual injection flow rate, providing strong technical support for the evaluation of the steam injection effect downhole.

[0087] When the production well is producing normally, the measurement system can monitor the flow rate of the downhole production profile and measure the actual production situation of the oil layer 8 through the sensor short section 1. The sensor short section 1 transmits the signal through the optical cable 2 to the ground data processing system 6 for data collection. The data collected by the data processing system 6 is processed to calculate the actual production profile, providing strong technical support for the evaluation of the downhole production effect.

[0088] like Figure 4 As shown, it is a downhole steam injection flow rate and liquid production profile measurement system for a horizontal well. The system is mainly a downhole steam injection flow rate and liquid production profile measurement system based on distributed optical fiber sensing, including a two-phase flow sensor short section 1, a stainless steel armored optical cable 2, an oil pipe 3, an optical cable fixing and straightening device 4, a distributed acoustic sensor demodulation device 5, a data processing system 6, an injector 7, a packer 9, and a pump 10 connected in sequence. On the ground, the distributed acoustic sensor demodulation device 5 and the data processing system 6 are mainly connected with the optical cable 2, which is lowered into the wellbore through the wellhead. The optical cable 2 is fixed to the outside of the pump 10 and the oil pipe 3 through the optical cable straightening device 4. The optical cable 2 passes through the packer 9 through the traverser until it is lowered into the upper part of the oil layer 8. The sensor short section 1 and the optical cable 2 are located in the upper part of the oil layer 8. The bottom of the sensor short section 1 is connected to the injector 7 through the oil pipe 3, and the injector 7 is lowered to the engineering design position. The collected data signals are transmitted back to the ground optical fiber signal data processing system 6 via the optical fiber cable 2 for collection and processing.

[0089] When steam is injected into the production well, the measurement system measures the actual injection volume of the injector 7 through the sensor nipple 1. The sensor nipple 1 transmits the signal to the ground data processing system 6 through the optical cable 2 for data collection. The data collected by the data processing system 6 is processed to calculate the actual injection flow rate, providing strong technical support for the evaluation of the steam injection effect downhole.

[0090] When the production well is producing normally, the measurement system can monitor the flow rate of the downhole production profile and measure the actual production situation of the oil layer 8 through the sensor short section 1. The sensor short section 1 transmits the signal through the optical cable 2 to the ground data processing system 6 for data collection. The data collected by the data processing system 6 is processed to calculate the actual production profile, providing strong technical support for the evaluation of the downhole production effect.

[0091] The injector and packer described in Example 2 are mature thermal recovery tools and are universal, so no special requirements or introduction are made. This method is also applicable to the steam injection flow rate and liquid production profile test of the stratified steam injection well. The principle of the test is the same as described above, so no further elaboration is made here.

[0092] Example 3: Internal structure of downhole two-phase flow sensor sub

[0093] like Figure 5 As shown, the sensor short section is mainly composed of a fiber coiling cover 13, a fiber coiling sleeve 14, a short section inner tube 22, a short section outer tube 19, and wound optical fibers 17 and 18. The bare optical fiber is wound on the short section inner tube by using an optical fiber winding device, which is divided into a tightly wound section 17 and an interval wound section 18. At the same time, a prestress T0 is given during winding to ensure the strain coupling efficiency between the optical fiber and the short section. One end of the optical fiber is fused with the stainless steel armored optical cable 11 through a small hole reserved on the short section shoulder. The short section inner tube and the short section outer tube are connected by screws, and the short section shoulder is positioned and provided with a sealing gasket 16. The fiber coiling sleeve 14 is connected to the short section inner tube 21 by threads. The fiber coiling cover 13 is connected to the fiber coiling sleeve 14 by laser welding. The cover is provided with a small hole and equipped with an optical cable fastener 12 to facilitate the passage of the optical cable, the tightening of the optical cable, and the sealing to prevent the entry of fluid outside the short section. The short section sleeve 21 is connected to the short section outer tube 19 by screws and equipped with a sealing ring. Both ends of the short-joint inner tube 22 are connected to the oil pipe through oil pipe couplings.

[0094] During measurement, when the fluid passes through the sensor short section, it will generate high-frequency and large-amplitude excitation, and the vibration signal is sensed by the optical fiber of the wound section of the inner tube of the short section. Since the optical fiber of the tightly wound section is densely arranged and the winding section is short, it is considered that the vibration signal in this section is consistent. The host computer extracts the signal data of this section and averages it over the distance. The tightly wound section of the optical fiber is taken as a vibration measurement point, and the standard deviation (STD) of the signal of this vibration measurement point is calculated. Figure 8 As shown in Figure 1, the vibration signal STD has a fixed quadratic linear relationship with the pipeline flow rate under a fixed phase content. The spatiotemporal data collected by the interval winding section optical fiber are transformed into a two-dimensional Fourier transform to obtain a frequency wavenumber spectrum, as shown in Figure 1. Figure 6 As shown in the figure, the wave number spectrum shows two different lines on both sides of the origin. From the Doppler effect, we know that their slopes represent the upward speed of sound C and u and downlink speed C d , static sound speed V = (C u +C d ) / 2 has a corresponding relationship with the phase content. Figure 6 As shown in the figure, the pipeline vibration signal STD corresponds to the flow rate, and the slope of the spectrum velocity diagram corresponds to the phase content, so the oil-water two-phase flow rate in the downhole pipeline can be detected.

[0095] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art can still modify the technical solutions recorded in the aforementioned embodiments or replace some of the technical features therein with equivalents. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

[0096] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A downhole two-phase flow sensor sub based on optical fiber sensing, characterized in that: The downhole two-phase flow sensor pup joint based on optical fiber sensing includes a pup joint inner tube, a pup joint outer tube, a fiber coil cover, a fiber coil sleeve and a wound optical fiber. The wound optical fiber is wound on the pup joint inner tube, the pup joint inner tube is connected to the pup joint outer tube, the fiber coil sleeve is connected to the pup joint outer tube by welding, and the fiber coil cover is welded to the fiber coil sleeve.

2. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1 is characterized in that: The downhole two-phase flow sensor pup joint based on optical fiber sensing also includes a pup joint sleeve, which is connected to the pup joint outer tube through screws and is equipped with a sealing ring.

3. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1 is characterized in that: The downhole two-phase flow sensor pup joint based on optical fiber sensing also includes a sealing gasket. The pup joint inner tube and the pup joint outer tube are connected by screws, positioned by the axle shoulder of the pup joint inner tube, and sealed with the sealing gasket.

4. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1, characterized in that: The fiber coil cover is provided with small holes and equipped with fasteners to facilitate the passage, fastening and sealing of the wound optical fiber.

5. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1, characterized in that: When the wound optical fiber is wound around the short section inner tube, it is divided into a tightly wound section and an interval wound section.

6. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1, characterized in that: The optical cable outside the short section of the downhole two-phase flow sensor based on optical fiber sensing is a stainless steel armored oil well optical cable, which is fused with the wound optical fiber for well-to-ground optical signal transmission.

7. The downhole two-phase flow sensor sub based on optical fiber sensing according to claim 1, characterized in that: The two ends of the inner tube of the short section are connected to the oil pipe through an oil pipe coupling, and the fiber coil sleeve is connected to the inner tube of the short section through a thread.

8. Design and measurement method of downhole two-phase flow sensor pup joint based on optical fiber sensing, characterized in that: The design and measurement method of the downhole two-phase flow sensor pup joint based on optical fiber sensing adopts the downhole two-phase flow sensor pup joint based on optical fiber sensing as claimed in claim 1, comprising: Step 1, winding the wound optical fiber on the inner tube of the short section of the downhole two-phase flow sensor short section based on optical fiber sensing, which is divided into a tightly wound section and an interval wound section; Step 2: Connect the downhole two-phase flow sensor sub based on optical fiber sensing to the distributed acoustic sensor demodulation device, and the distributed acoustic sensor demodulation device is connected to the host computer data processing system; Step 3, lowering a downhole two-phase flow sensor sub based on optical fiber sensing into the wellbore; Step 4, fix the optical cable to the outer wall of the oil pipe by using an optical cable fixing centralizer, so that the optical cable and the downhole two-phase flow sensor short section based on optical fiber sensing are located at the upper part of the oil layer; Step 5: When the fluid passes through the downhole two-phase flow sensor pup joint based on optical fiber sensing, it will impact the pipe wall and cause the pipeline to vibrate laterally. The vibration signal is sensed through the optical fiber and transmitted to the ground data processing system through the optical cable for data collection. Step 6, performing a two-dimensional Fourier transform on the signal data of the interval winding section to obtain a frequency wavenumber spectrum; Step 7, average the signal data of the tightly wound section over the distance, take the tightly wound section of the optical fiber as a vibration measurement point, make the standard deviation STD of the vibration measurement point signal, substitute the STD and the mixed flow rate under the oil or water content into the fitting relationship, and calculate the pipeline mixed flow rate.

9. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 1, a prestress T0 is given to the wound optical fiber to ensure the strain coupling efficiency between the optical fiber and the short section; the interval winding section of the optical fiber has a long winding distance, which corresponds to a long distance of sound transmission in the fluid; because the speed of sound transmission in different media is different, the speed of sound propagation in the fluid can be detected, and the phase content can be measured corresponding to the sound velocity diagram of different phase volume fractions.

10. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 9, characterized in that: In step 1, a two-dimensional Fourier transform is performed on the spatiotemporal data collected by the interval-wound optical fiber to obtain a frequency wavenumber spectrum, and then two oblique lines are obtained on the frequency wavenumber spectrum through a fitting algorithm. The formula is: It can be seen that the slope of the oblique line represents the speed of sound wave propagation in the medium; the slopes of the two oblique lines on the frequency wave number diagram represent the upward speed of sound C and u and downlink speed C d , and according to the Doppler effect, the static sound speed V = (C u +C d ) / twenty two).

11. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 10, characterized in that: In step 1, there is a monotonically decreasing relationship between the sound velocity of the oil-water two-phase and the phase content, that is, when the oil content increases, the sound velocity decreases, and when the water content increases, the sound velocity increases; this relationship can be fitted with a cubic function to obtain a better fitting effect; therefore, it is only necessary to obtain the static sound velocity v from the collected signal, and the oil or water content can be calculated by the fitting formula; the optical fiber in the tightly wound section is densely arranged and the winding section is short, so it is considered that the vibration signal in this section is consistent; the pipeline filled with liquid is simplified into a one-dimensional beam model, and combined with the beam deflection equation, the pipeline acceleration and pressure fluctuation can be established Relationship: The pressure fluctuation p′ is proportional to the fluctuation of the fluid velocity, i.e., the axial velocity u′ and the radial velocity v′ 12. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 11, characterized in that: In step 1, the tightly wound section of the optical fiber is used as a vibration measurement point, and the standard deviation STD of the vibration measurement point signal is calculated. In theory, there is a quadratic linear relationship between the standard deviation of the pipeline flow-induced vibration signal and the flow rate in the pipe. Before using the downhole two-phase flow sensor pup joint based on optical fiber sensing, it is necessary to calibrate the fitting relationship between the static sound velocity and the oil or water content, as well as the fitting relationship between the STD and the mixed flow at various oil or water content in the oil-water circulation flow test platform.

13. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 3, one end of the fiber optic sensing downhole two-phase flow sensor short section is connected to the oil pipe, and the other end is connected to the dispenser or the oil pump. According to the engineering test requirements, the sensor short section is connected to the appropriate position of the oil pipe and lowered into the wellbore.

14. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 10, characterized in that: In step 6, the static sound velocity is calculated using formulas (1) and (2), and the static sound velocity is substituted into the fitting relationship between the static sound velocity and the oil or water content to calculate the oil or water content.

15. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 4, the vertical well downhole fluid production profile flow monitoring system only requires a downhole two-phase flow sensor pup joint based on optical fiber sensing, which is located in the upper part of the oil layer.

16. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 4, the horizontal well downhole fluid production profile flow monitoring system requires multiple downhole two-phase flow sensor short sections based on optical fiber sensing, which are distributed in the horizontal oil layer.

17. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 4, the vertical well downhole steam injection flow rate and liquid production profile measurement system requires a downhole two-phase flow sensor short section based on optical fiber sensing, which is located on the upper part of the injector.

18. The design and measurement method of a downhole two-phase flow sensor pup joint based on optical fiber sensing according to claim 8, characterized in that: In step 4, the horizontal well downhole steam injection flow rate and liquid production profile measurement system requires multiple downhole two-phase flow sensor short sections based on optical fiber sensing, distributed in the horizontal oil layer, and requires an injection dispenser.

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