A flow measurement device, method, apparatus, and media for an oilfield production well

Abstract

The application discloses a flow measuring device, method, device and medium of an oilfield production well, and is applied to the field of flow measurement. The conductive ion jet of the device is arranged at one end of a probe, first and fourth metal rings are arranged at two ends of a metal ring group, and an electric field is formed after power supply. The second and third metal rings are arranged in the middle of the metal ring group; when conductive ions flow, a potential difference signal is generated between the second and third metal rings, and a processor determines the time of the conductive ions flowing through the metal ring group according to the potential difference signal. The processor can determine the flow rate of the fluid according to the time of the conductive ions flowing through the metal ring group, and then the flow rate of the fluid can be determined according to the flow rate and the size of the well. The scheme cannot cause the device to be unable to operate due to crude oil or other impurities, and can ensure reliable flow measurement.

Description

Technical Field

[0001] This application relates to the field of flow measurement, and in particular to a flow measurement device, method, apparatus, and medium for oilfield production wells. Background Technology

[0002] During oilfield development, specialized logging instruments are frequently deployed into wells to monitor the oil-water mixture produced in each oil layer; this is known as production profile logging. To improve development efficiency and extract as much crude oil as possible from the wellbore, adjacent well water injection and production well oil extraction are often implemented. This involves injecting water into a well adjacent to the production well, which in turn drives the crude oil to flow towards the production well. The pumping unit then extracts the oil-water mixture. Oilfield production wells use steel casing, which is cemented to the formation. In the oil-bearing section, the steel casing has perforations that connect it to the formation, creating a channel for fluid flow inside and outside the casing. The oil-water mixture flows within the production well. Oilfield production well logging, also known as oilfield development logging, uses specialized logging instruments to measure the production of crude oil and water within a steel casing hundreds to thousands of meters below the surface, or the water absorption of different formations during water injection. This allows for understanding the flow rate of fluids produced or absorbed by the formation in each perforated section, enabling accurate engineering evaluation of the well's occurrence and reservoir development characteristics. Measuring the amount of fluid produced or absorbed by different perforated sections per unit time is called flow rate logging. Flow rate logging is a crucial method for evaluating the production and injection effectiveness of oilfield production wells and water injection wells. Currently, turbine flow rate measurement technology is primarily used for oilfield production well flow rate logging. Turbine flow rate logging uses a mechanical turbine to measure the flow rate in the producing formation within the well. It is used in combination with a flow collector umbrella. By using the flow collector umbrella to concentrate the flow, the fluid velocity flowing through the instrument's turbine is significantly increased, the turbine's starting discharge is reduced, and the linearity and accuracy of the measurement results are enhanced. When fluid passes through the turbine, it drives the turbine to rotate. The rotation speed is proportional to the fluid velocity. The turbine rotation drives the Hall effect grating inside the instrument to rotate via magnetic coupling, thereby obtaining the fluid velocity and thus the flow rate.

[0003] However, in turbine flow logging, crude oil and other impurities may prevent the flow collecting umbrella from fully closing. When changing the target layer, casing couplings and burrs may also damage the flow collecting umbrella. In addition, if heavy oil fills the turbine chamber or iron filings and debris are adsorbed and accumulated on the upper magnetic poles of the turbine, the turbine may not be able to rotate. It can be seen that the current turbine flow logging technology cannot guarantee that the components being measured can operate normally, and therefore cannot guarantee reliable flow measurement of oilfield production wells.

[0004] Therefore, ensuring reliable measurement of flow rate in oilfield production wells is a problem that urgently needs to be solved by those skilled in the art. Summary of the Invention

[0005] The purpose of this application is to provide a flow measurement device, method, apparatus, and medium for oilfield production wells to ensure stable flow measurement of oilfield production wells.

[0006] To solve the above-mentioned technical problems, this application provides a flow measurement device for oilfield production wells, including: a probe, at least one metal ring assembly, a conductive ion injector, and a processor;

[0007] The conductive ion ejector is disposed at one end of the probe and is used to eject conductive ions when the probe is placed in the well so that they follow the fluid in the well to flow through the outside of the probe.

[0008] The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring. Each metal ring is sequentially disposed on the line connecting the two ends of the probe, and the ring surface of each metal ring intersects with the line connecting the two ends of the probe. The first metal ring and the fourth metal ring are disposed at the two ends of the metal ring assembly and form an electric field after power is supplied. The second metal ring and the third metal ring are disposed in the middle of the metal ring assembly.

[0009] The processor is connected to the second metal ring and the third metal ring respectively, and is used to determine the time for the conductive ions to flow through the metal ring group based on the potential difference signal between the second metal ring and the third metal ring; the processor is also used to determine the flow rate of the fluid based on the time for the conductive ions to flow through the metal ring group, and to determine the flow rate of the fluid based on the flow rate and the size of the well.

[0010] Preferably, there are two metal ring groups, which are disposed on the probe and at different distances from the port of the probe;

[0011] The step of determining the flow rate of the fluid based on the time it takes for the conductive ions to flow through the metal ring assembly includes:

[0012] The flow rate is determined based on the distance between the two metal ring groups and the time difference between the conductive ions flowing through the two metal ring groups.

[0013] Preferably, the annular surface of each metal ring in the metal ring assembly is perpendicular to the line connecting the two ends of the probe.

[0014] Preferably, the inner layer of the probe frame is made of metal; the inner metal layer of the probe frame is covered with an insulating layer, and an insulating sleeve is installed between each metal ring of the metal ring assembly.

[0015] Preferably, determining the flow rate of the fluid based on the flow velocity and the size of the well includes:

[0016] The flow rate is determined based on the flow velocity and the wellbore diameter.

[0017] Preferably, it further includes: a lantern body;

[0018] The lantern body is disposed at both ends of the probe to keep the probe in the middle position of the well when measuring the flow rate.

[0019] To solve the above-mentioned technical problems, this application also provides a flow measurement method for an oilfield production well, applied to a flow measurement device for an oilfield production well. The device includes: a probe, at least one metal ring assembly, a conductive ion ejector, and a processor. The conductive ion ejector is disposed at one end of the probe. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring, each metal ring being sequentially disposed on the line connecting the two ends of the probe, and the ring surface of each metal ring intersects the line connecting the two ends of the probe. The first metal ring and the fourth metal ring are disposed at both ends of the metal ring assembly, forming an electric field after power supply. The second metal ring and the third metal ring are disposed in the middle of the metal ring assembly. The processor is connected to the second metal ring and the third metal ring respectively. The method includes:

[0020] The time for the conductive ions to flow through the metal ring assembly is determined based on the potential difference signal between the second and third metal rings; wherein, when the probe is placed inside the well, the conductive ion ejector ejects the conductive ions to follow the fluid inside the well through the outside of the probe;

[0021] The flow rate of the fluid is determined based on the time it takes for the conductive ions to flow through the metal ring assembly;

[0022] The flow rate of the fluid is determined based on the flow velocity and the size of the well.

[0023] To solve the above-mentioned technical problems, this application also provides a flow measurement device for oilfield production wells, including: a memory for storing computer programs;

[0024] A processor is used to execute computer programs to implement the steps of the above-mentioned oilfield production well flow measurement method.

[0025] To address the aforementioned technical problems, this application also provides a computer-readable storage medium storing a computer program, which, when executed by a processor, implements the steps of the above-mentioned method for measuring the flow rate of an oilfield production well.

[0026] The flow measurement device for oilfield production wells provided in this application includes a probe, at least one metal ring assembly, a conductive ion ejector, and a processor. When the device is placed inside the well for measurement, the fluid inside the well flows past the outside of the probe. The conductive ion ejector is located at one end of the probe. During measurement, the fluid inside the well moves upward, so the port of the device closest to the conductive ion ejector faces downward, and the conductive ion ejector ejects conductive ions to follow the fluid flow past the outside of the probe. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring. Each metal ring is sequentially arranged on the line connecting the two ends of the probe, and the ring surface of each metal ring intersects with the line connecting the two ends of the probe. The first and fourth metal rings are located at the two ends of the metal ring assembly and form an electric field after power is supplied. The second and third metal rings are located in the middle of the metal ring assembly. When conductive ions flow through, a potential difference signal is generated between the second and third metal rings. The processor is connected to the second and third metal rings respectively and is used to determine the time it takes for conductive ions to flow through the metal ring assembly based on this potential difference signal. The processor can determine the fluid velocity based on the time it takes for conductive ions to pass through the metal ring assembly, and then determine the fluid flow rate based on the velocity and the well size. The equipment provided in this solution injects conductive ions into the fluid inside the well. The fluid flows directly past the outside of the probe, preventing the equipment from malfunctioning due to crude oil or other impurities, thus ensuring reliable flow rate measurement of oilfield production wells.

[0027] This application also provides a method, apparatus, and computer-readable storage medium for measuring the flow rate of an oilfield production well, which corresponds to the above-mentioned equipment and therefore has the same beneficial effects as the above-mentioned equipment. Attached Figure Description

[0028] To more clearly illustrate the embodiments of this application, the accompanying drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0029] Figure 1 A partial structural schematic diagram of a flow measurement device for an oilfield production well provided in this application embodiment;

[0030] Figure 2 This application provides a schematic diagram of the working process of a metal ring assembly.

[0031] Figure 3 A flowchart of a flow measurement method for an oilfield production well provided in this application embodiment;

[0032] Figure 4 This is a structural diagram of a flow measurement device for an oilfield production well provided in an embodiment of this application. Detailed Implementation

[0033] The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the protection scope of this application.

[0034] Oilfield production well logging, also known as oilfield development logging, uses specialized logging instruments to measure the production of crude oil and water within a steel casing hundreds to thousands of meters below the surface, or to measure the water absorption of different formation layers during water injection. This allows for understanding the flow rate of fluids produced or absorbed by the formation in each perforated section, providing a correct engineering evaluation of the well's occurrence and reservoir development characteristics. During the reciprocating pumping operation of an oilfield production well, one or more producing layers simultaneously flow a mixture of oil and water into the well from the formation. The pump then extracts this mixture, producing an oil-water mixture. In oilfield development, it is necessary to know the amount of oil-water mixture produced per unit time for each producing layer at regular intervals. The purpose is to evaluate the development effectiveness of individual producing layers and provide a basis for subsequent measures and the exploration of producing layers in surrounding newly drilled wells. By measuring the flow rate at the top of each producing layer within an oilfield production well using a flow logging instrument, the flow rate of the produced oil-water mixture from each layer can be determined. This is flow logging. Except for flowing wells, the oil-water mixture in all oilfield production wells is extracted from the well using a pumping unit. Powered by the power grid, the pumping unit moves up and down periodically, extracting fluid with each upward movement. The producing layer refers to the oil-bearing formation below the wellbore. This formation is connected to the wellbore through perforations in the steel casing within the well.

[0035] The core of this application is to provide a flow measurement device, method, apparatus, and medium for oilfield production wells to ensure reliable flow measurement of oilfield production wells.

[0036] To enable those skilled in the art to better understand the present application, the present application will be further described in detail below with reference to the accompanying drawings and specific embodiments.

[0037] Currently, turbine flow measurement technology is mainly used for flow logging in oilfield production wells. Turbine flow logging uses a mechanical turbine to measure the flow rate in the producing formation within the well, in combination with a flow collector. When fluid passes through the turbine, it drives the turbine to rotate, and the rotational speed is proportional to the fluid velocity. The turbine rotation, via magnetic coupling, drives the rotation of the Hall effect grating inside the instrument, thereby obtaining the fluid velocity and thus the flow rate. However, in turbine flow logging, crude oil and other impurities may prevent the flow collector from completely closing. When changing the target formation, casing couplings and burrs may also damage the flow collector. In addition, if heavy oil fills the turbine chamber or iron filings and debris accumulate on the upper magnetic poles of the turbine, the turbine may not be able to rotate, thus making it impossible to reliably measure the flow rate of the oilfield production well. In addition to turbine flow logging, there are several other flow measurement technologies, including electromagnetic flow logging, isotope tracer logging, and oxygen-activated water flow logging. Electromagnetic flow logging works by having a conductive fluid (water) flow through an electromagnetic flow sensor, cutting the sensor's magnetic induction lines and generating an induced current in the probe coil proportional to the fluid velocity. The flow rate is then determined by measuring the magnitude of this induced current. However, electromagnetic flow logging is only suitable for water wells. If the fluid contains oil, the crude oil will contaminate the probe, leading to abnormal logging responses, including chaotic signals, extremely weak signals, and false readings. In isotope tracer logging, the distance between the vent nozzle and the gamma probe is far, resulting in severe isotope diffusion. Radioactive elements contaminate the instrument, and the wellbore fluid between closely spaced production layers affects peak signal formation, causing severe signal tailing and impacting flow rate determination. Oxygen-activated water flow logging is also only suitable for water wells and high-water-cut oil wells. As the oil content increases, the measurement results become rapidly distorted.

[0038] It is evident that existing flow measurement technologies for oil production wells are limited by their measurement principles and instrument structures, making it impossible to obtain reliable flow measurement results. In order to fill the technical gap in flow measurement for oilfield production wells, this application provides a flow measurement device for oilfield production wells, specifically including a probe, at least one metal ring assembly, a conductive ion injector, and a processor.

[0039] Specifically, the shape of the probe is not limited; a cylindrical structure is acceptable. The probe can be a hollow cavity to accommodate various internal wiring, allowing the fluid inside the well to flow over the outside of the probe. A conductive ion ejector is positioned at one end of the probe and ejects conductive ions to follow the fluid flow over the probe's exterior. Specifically, the conductive ion ejector can be a conductive ion solution ejection ring, used to spray a solution containing conductive ions in all directions. The specific type of conductive ions and the solution containing them are not limited. An environmentally friendly conductive ion solution is used to generate an electrical signal by flowing through an electric field, avoiding radioactive isotope contamination common in isotope tracer flow logging. When the equipment is placed inside the well for measurement, the fluid inside the well flows over the outside of the probe. During measurement, the fluid inside the well moves upwards, so the port of the equipment closest to the conductive ion ejector faces downwards, allowing the ejector to spray conductive ions to follow the fluid flow over the probe. In actual operation, a lantern-shaped device can be added to each end of the probe to center it and achieve better measurement results.

[0040] The number of metal ring groups is not limited. If there is only one metal ring group, the fluid velocity can be determined by the distance between the metal ring group and the conductive ion ejector, and the time taken for the conductive ions to travel from the ejection point to the metal ring group. However, the initial velocity of the conductive ion ejector when it first ejects the conductive ions may affect the measurement results. Therefore, two metal ring groups can be set, with the two metal ring groups placed on the probe at different distances from the probe port. In practical applications, to improve the accuracy of the test results or to avoid measurement failure due to damage to the metal ring groups, multiple metal ring groups can be added. The specific number and position of each metal ring group are not limited. Each metal ring group includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring, which are sequentially arranged on the line connecting the two ends of the probe. When the conductive ions flow through the probe, they pass through each metal ring of the metal ring group. Preferably, the ring surface of each metal ring in the metal ring group is perpendicular to the line connecting the two ends of the probe, and each metal ring can be wrapped around the outer perimeter of the cylinder. Sometimes, to improve probe durability, the probe frame can be made of metal. However, metal can affect the formation of the DC electric field and the generation of the potential difference signal. Therefore, an insulating layer can be applied to the outside of the metal probe frame, and insulating sleeves can be installed between the metal rings to prevent short circuits. To prevent the initial velocity of conductive ions from affecting the measurement structure, the positions of each metal ring assembly can be far away from the conductive ion ejector, thus ensuring that the measured velocity of the conductive ions is basically consistent with the fluid flow rate.

[0041] The specific positions of each metal ring are not limited. The first and fourth metal rings are positioned at both ends of the metal ring assembly, forming an electric field after power is supplied. Specifically, paired electrodes are placed within a conductive fluid. When direct current is supplied to the paired electrodes, the current flows from the positive to the negative electrode through the conductive fluid, thus creating an electric field within the fluid. Based on this principle, a low-voltage direct current supply is provided to the first and fourth metal rings to form a direct current electric field. The second and third metal rings are positioned in the middle of the metal ring assembly to detect potential difference signals. Due to the electric field formed between the first and fourth metal rings, a potential difference signal is generated between the second and third metal rings when conductive ions flow through the metal ring assembly. The time when the generated potential difference signal represents the time taken for conductive ions to flow through each metal ring assembly is recorded. The time between each potential difference signal represents the time taken for conductive ions to flow through each metal ring assembly. The processor is connected to the second and third metal rings of each metal ring assembly to obtain the potential difference signal generated when conductive ions flow through each metal ring assembly and the time between each potential difference signal. Because the multiple metal ring groups are located at different positions, the time it takes for conductive ions to flow through each metal ring group is also different when they flow from one end of the probe to the other. The processor can determine the fluid velocity based on the distance between each metal ring group and the time difference of conductive ions flowing through each metal ring group, and determine the fluid flow rate based on the flow velocity and the size of the well.

[0042] Taking two sets of metal rings as an example, in an oilfield production well, as the pumping unit operates, the oil-water mixture flows upwards within the well. A probe is inserted into the well, remaining stationary within the fluid. A low-voltage direct current is supplied to the first and fourth metal rings on the probe, creating a direct current electric field. Each of the two metal ring sets generates a direct current electric field. A conductive ion ejector at the lower end of the probe injects a conductive ion solution outwards. This solution moves upwards with the fluid in the well, generating two electrical signals as it flows through the two sets of electric fields. Specifically, a potential difference signal is generated between the second and third metal rings of each set. There is a time difference between these two signals because the interval between the two sets of metal rings on the probe is fixed. By analyzing the time difference between the two signals and the fixed interval between the two sets of metal rings, the flow velocity of the fluid in the well can be obtained. Since the wellbore diameter of each oilfield production well is fixed, the flow velocity and the cross-sectional area of ​​the wellbore can be used to determine the flow rate of oil and water produced per unit time in that production well.

[0043] The following description, in conjunction with the accompanying drawings, illustrates the situation of the two metal ring assemblies. Figure 1 This application provides a partial structural schematic diagram of a flow measurement device for an oilfield production well, as illustrated in the embodiments of this application. Figure 1As shown, two chemically and electrically stable metal ring groups, designated as the first metal ring group 2 and the second metal ring group 3, are arranged on the rod of the insulated probe 1. The first metal ring group 2 consists of metal ring A1, metal ring M1, metal ring N1, and metal ring B1; the second metal ring group 3 consists of metal ring A2, metal ring M2, metal ring N2, and metal ring B2. Each metal ring is led out through the hollow space of the rod of the insulated probe 1 by a high-temperature resistant lead wire. A1, B1 and A2, B2 are connected to the positive and negative terminals of two independent low-voltage DC power supplies of the electronic circuitry, respectively. M1, N1 and M2, N2 are connected to the input terminals of two signal processing circuits of the electronic circuitry, respectively. Because the probe 1 is inserted into the oil-water mixture in the oilfield production well, and the oil-water mixture in the well contains a large number of conductive ions, the oil-water mixture in the well is conductive. A low-voltage DC current is supplied between A1 and B1, thus forming a stable DC electric field between them; a low-voltage DC current is supplied between A2 and B2, thus forming a stable DC electric field between them. A conductive ion injector 4 is connected to the lower end of the flow probe 1, which can electrically control the circumferential spraying of a high-concentration conductive ion solution. The conductive ion solution mass flows upward with the fluid in the oilfield production well. The conductive ion solution can be prepared by mixing sodium chloride or sodium hydroxide, alcohol, and water in a specific ratio. Two DC electric fields are emitted by electrodes A1 and A2, which return through electrodes B1 and B2 respectively. A conductive ion solution is instantaneously sprayed circumferentially by the conductive ion ejector 4 at the bottom of probe 1. As the fluid in the wellbore flows upward, the ion cluster first flows through measuring electrodes N1 and M1, generating an excitation potential difference signal V1. After traveling a certain distance, it flows through measuring electrodes M2 and N2, generating another excitation potential difference signal V2. Since the metal rings have identical geometry and the distance between the two sets of metal rings remains constant, the flow velocity of the fluid in the wellbore can be calculated based on the time difference between the two signals V2 and V1, combined with the corresponding interval distance between the two sets of metal rings. Then, based on the inner diameter of the oil / water well casing, the flow rate of the fluid in the wellbore can be calculated. The main body of probe 1 is a hollow cylinder with an inner cylindrical stainless steel frame. From the inside out, it consists of: a hollow stainless steel frame, an insulating layer, and an outer insulating sleeve. Embedded metal rings are located on the insulating sleeve. The cylinder has clamping threads at both ends to fix the metal rings and the compacted insulating rings. The two ends of the frame are connected to other instruments via the threads. In this example, probe 1 consists of 8 metal rings arranged symmetrically in two groups. The middle A1 and A2 are for electric field emission, and the two ends B1 and B2 are for electric field circuits. M1 and N1 and M2 and N2 are for signal measurement metal rings. At the top and bottom of probe 1, there are lantern-shaped supports 5, which are multiple arc-shaped spring pieces evenly distributed longitudinally at both ends of probe 1, forming a lantern-shaped support. The lantern-shaped supports 5 can keep probe 1 centered in the oilfield production well.Because probe 1 is located within an oil-water mixture within a production well in the oilfield, and this mixture is conductive, two independent 12V DC power supplies are simultaneously supplied to A1, B1, and A2, B2, forming two separate DC electric fields. The conductive ion solution is instantaneously circumferentially ejected by the conductive ion ejector 4 at the bottom of probe 1. As the fluid flows upwards within the wellbore, the ion cluster first flows through measuring electrodes N1 and M1, generating an excitation potential difference signal V1. After traveling a distance, it flows through measuring electrodes M2 and N2, generating another excitation potential difference signal V2. V1 and V2 are pre-processed, encoded, and driven before being transmitted to the surface system via the logging cable. The pre-processing, encoding, driving, and transmission of the electrical signals to the surface logging system via the logging cable are not described in detail here. It is important to note that... Figure 1 The structure and scheme shown are only one form provided in this example and do not limit other schemes of this application. For example, the number of metal ring groups, the installation order of each metal ring, etc. can be set according to the actual situation.

[0044] In addition, to more clearly explain the workflow of the metal ring assembly, the following will be provided: Figure 1 The structure is abstracted, and the function of each metal ring is explained in detail. Figure 2 This application provides a schematic diagram of the working process of a metal ring assembly, as shown in the embodiment. Figure 2 As shown, it includes probe 1, first metal ring group 2, and second metal ring group 3. Each metal ring is described separately here; for the actual structure, please refer to [link to documentation]. Figure 1 The first metal rings A1 and A2 are the emitting ends of the DC electric field, and the fourth metal rings B1 and B2 are the returning ends of the DC electric field. When the conductive ion cluster passes through, an excitation potential difference signal V1 is generated between M1 and N1, and an excitation potential difference signal V2 is generated between M2 and N2. Based on the time difference between the two excitation potential difference signals and the corresponding interval distance between the first metal ring group 2 and the second metal ring group 3, the moving speed of the conductive ion cluster can be calculated, thereby obtaining the flow rate of the fluid.

[0045] This embodiment solves the problems of flow logging failure and data distortion caused by limitations of existing technology measurement principles, instrument damage, and malfunctions in heavy oil production wells in oilfields. It establishes a flow testing method based on downhole artificial electric fields, eliminates radioactive isotope contamination, improves the flow testing technology for oilfield production wells, meets the flow testing needs of production wells in heavy oil blocks of oilfields, and is also applicable to flow testing of light oil and water wells, supporting oilfield development and production capacity construction.

[0046] The flow measurement device for oilfield production wells provided in this application includes a probe, at least one metal ring assembly, a conductive ion ejector, and a processor. When the device is placed inside the well for measurement, the fluid inside the well flows past the outside of the probe. The conductive ion ejector is located at one end of the probe. During measurement, the fluid inside the well moves upward, so the port of the device closest to the conductive ion ejector faces downward, and the conductive ion ejector ejects conductive ions to follow the fluid flow past the outside of the probe. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring. Each metal ring is sequentially arranged on the line connecting the two ends of the probe, and the ring surface of each metal ring intersects with the line connecting the two ends of the probe. The first and fourth metal rings are located at the two ends of the metal ring assembly and form an electric field after power is supplied. The second and third metal rings are located in the middle of the metal ring assembly. When conductive ions flow through, a potential difference signal is generated between the second and third metal rings. The processor is connected to the second and third metal rings respectively and is used to determine the time it takes for conductive ions to flow through the metal ring assembly based on this potential difference signal. The processor can determine the fluid velocity based on the time it takes for conductive ions to pass through the metal ring assembly, and then determine the fluid flow rate based on the velocity and the well size. The equipment provided in this solution injects conductive ions into the fluid inside the well. The fluid flows directly past the outside of the probe, preventing the equipment from malfunctioning due to crude oil or other impurities, thus ensuring reliable flow rate measurement of oilfield production wells.

[0047] To improve the durability of the equipment, the probe frame is made of metal, specifically stainless steel, to ensure its service life. However, metal materials can affect the formation of the DC electric field and the generation of the potential difference signal. Therefore, an insulating layer can be applied to the outside of the metal probe frame, and insulating sleeves can be installed between the metal rings to prevent short circuits. The probe frame provided in this embodiment is made of metal, which improves durability, and an insulator is also provided to ensure the reliable formation of the DC electric field and reliable measurement results.

[0048] In general, the wellbore diameter of each production well in an oilfield is fixed. As a preferred embodiment for calculating flow rate, determining the fluid flow rate based on the flow velocity and the well size includes: determining the flow rate based on the flow velocity and the wellbore diameter. Because the wellbore diameter of each production well in an oilfield is fixed, the flow rate of oil and water produced by this production well per unit time can be obtained by using the flow velocity and the cross-sectional area of ​​the wellbore.

[0049] In practical implementation, if there is only one metal ring group, the fluid velocity can be determined by the distance between the metal ring group and the conductive ion ejector, and the time taken for the conductive ions to travel from the ejection point to the metal ring group. However, the initial velocity of the conductive ion ejector when it first ejects the conductive ions may affect the measurement results. Setting up too many metal ring groups would increase costs. Therefore, to improve measurement and save costs, two metal ring groups are used. Correspondingly, determining the fluid velocity based on the time it takes for the conductive ions to pass through the metal ring group includes determining the velocity based on the distance between the two metal ring groups and the time difference between the two potential difference signals generated sequentially when the conductive ions pass through the two metal ring groups. The smaller the time difference, the faster the velocity. For specific calculation methods, please refer to the above embodiment, which will not be described in detail here.

[0050] To address the aforementioned technical problems, this embodiment also provides a flow measurement method for oilfield production wells, applied to a flow measurement device for oilfield production wells. The device includes: a probe, at least one metal ring assembly, a conductive ion ejector, and a processor. The conductive ion ejector is disposed at one end of the probe. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring, with each metal ring sequentially disposed on the line connecting the two ends of the probe, and the ring surface of each metal ring intersecting the line connecting the two ends of the probe. The first and fourth metal rings are disposed at both ends of the metal ring assembly, forming an electric field after power is supplied. The second and third metal rings are disposed in the middle of the metal ring assembly. The processor is connected to the second and third metal rings respectively. Figure 3 A flowchart of a flow measurement method for an oilfield production well provided in this application embodiment is shown below. Figure 3 As shown, the method includes the following steps:

[0051] S10: Determine the time for conductive ions to flow through the metal ring assembly based on the potential difference signal between the second and third metal rings.

[0052] When the probe is placed inside the well, the conductive ion ejector sprays conductive ions to follow the fluid inside the well through the outside of the probe.

[0053] S11: Determine the fluid velocity based on the time it takes for conductive ions to flow through the metal ring assembly.

[0054] S12: Determine the flow rate of the fluid based on the flow velocity and the size of the well.

[0055] Since the embodiments of the method section correspond to the embodiments of the device section, please refer to the description of the embodiments of the device section for the embodiments of the method section, and they will not be repeated here.

[0056] The flow measurement method for oilfield production wells provided in this embodiment corresponds to the aforementioned equipment and therefore has the same beneficial effects. This application embodiment provides a flow measurement method for oilfield production wells based on a downhole artificial electric field. It employs a method of directly contacting the flowing fluid within the oilfield production well. By measuring the electrical signals generated by the flow of an environmentally friendly ionic solution through near and far electric fields, and combining the distance between the two sets of electric fields, the flow velocity of the fluid within the well is directly obtained, and thus the flow rate is obtained. This solves the problems of flow logging failures and data distortion caused by limitations in measurement principles, instrument damage, and malfunctions in turbine flow, electromagnetic flow, isotope tracing, and oxygen-activated water flow logging techniques in heavy oil wells. The method is also applicable to flow measurement in light oil and water wells.

[0057] The above embodiments have described in detail the flow measurement method for oilfield production wells. This application also provides embodiments corresponding to the flow measurement device for oilfield production wells. From a hardware perspective, this embodiment provides another flow measurement device for oilfield production wells. Figure 4 A structural diagram of the flow measurement device for an oilfield production well provided in the embodiments of this application is shown below. Figure 4 As shown, the flow measurement device for oilfield production wells includes: a memory 20 for storing computer programs;

[0058] The processor 21 is used to execute a computer program to implement the steps of the flow measurement method for oilfield production wells as described in the above embodiments.

[0059] The flow measurement device for oilfield production wells provided in this embodiment may include, but is not limited to, smartphones, tablets, laptops, or desktop computers.

[0060] The processor 21 may include one or more processing cores, such as a quad-core processor or an octa-core processor. The processor 21 may be implemented using at least one of the following hardware forms: Digital Signal Processor (DSP), Field-Programmable Gate Array (FPGA), or Programmable Logic Array (PLA). The processor 21 may also include a main processor and a coprocessor. The main processor, also known as the Central Processing Unit (CPU), is used to process data in the wake-up state; the coprocessor is a low-power processor used to process data in the standby state. In some embodiments, the processor 21 may integrate a Graphics Processing Unit (GPU), which is responsible for rendering and drawing the content to be displayed on the screen. In some embodiments, the processor 21 may also include an Artificial Intelligence (AI) processor, which is used to handle computational operations related to machine learning.

[0061] The memory 20 may include one or more computer-readable storage media, which may be non-transitory. The memory 20 may also include high-speed random access memory and non-volatile memory, such as one or more disk storage devices or flash memory devices. In this embodiment, the memory 20 is used to store at least the following computer program 201, which, after being loaded and executed by the processor 21, is capable of implementing the relevant steps of the flow measurement method for oilfield production wells disclosed in any of the foregoing embodiments. In addition, the resources stored in the memory 20 may also include an operating system 202 and data 203, and the storage method may be temporary or permanent storage. The operating system 202 may include Windows, Unix, Linux, etc. The data 203 may include, but is not limited to, data related to the flow measurement method for oilfield production wells.

[0062] In some embodiments, the flow measurement device for oilfield production wells may further include a display screen 22, an input / output interface 23, a communication interface 24, a power supply 25, and a communication bus 26.

[0063] Those skilled in the art will understand that the structure shown in the figure does not constitute a limitation on the flow measurement device for oilfield production wells and may include more or fewer components than shown.

[0064] The flow measurement device for oilfield production wells provided in this application includes a memory and a processor. When the processor executes the program stored in the memory, it can implement the following method: flow measurement method for oilfield production wells.

[0065] The flow measurement device for oilfield production wells provided in this embodiment corresponds to the method described above, and therefore has the same beneficial effects as the method described above.

[0066] Finally, this application also provides an embodiment corresponding to a computer-readable storage medium. The computer-readable storage medium stores a computer program, which, when executed by a processor, implements the steps described in the above method embodiments.

[0067] It is understood that if the methods in the above embodiments are implemented as software functional units and sold or used as independent products, they can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and executes all or part of the steps of the methods described in the various embodiments of this application. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0068] The computer-readable storage medium provided in this embodiment corresponds to the method described above, and therefore has the same beneficial effects as the method described above.

[0069] The foregoing provides a detailed description of the flow measurement equipment, method, apparatus, and medium for oilfield production wells provided in this application. The various embodiments in the specification are described in a progressive manner, with each embodiment focusing on its differences from other embodiments. Similar or identical parts between embodiments can be referred to interchangeably. For the apparatus disclosed in the embodiments, since it corresponds to the method disclosed in the embodiments, the description is relatively simple; relevant parts can be referred to in the method section. It should be noted that those skilled in the art can make several improvements and modifications to this application without departing from the principles of this application, and these improvements and modifications also fall within the protection scope of the claims of this application.

[0070] It should also be noted that, in this specification, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes the aforementioned element.

Claims

1. A flow measurement device for oilfield production wells, characterized in that, include: The probe, at least one metal ring assembly, a conductive ion ejector, and a processor; The conductive ion ejector is disposed at one end of the probe and is used to eject conductive ions when the probe is placed in the well so that they follow the fluid in the well to flow through the outside of the probe. During measurement, the port of the probe closest to the conductive ion ejector faces downward. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring. Each metal ring is sequentially disposed on the line connecting the two ends of the probe, and the ring surface of each metal ring intersects with the line connecting the two ends of the probe. The first metal ring and the fourth metal ring are disposed at the two ends of the metal ring assembly and form an electric field after power is supplied. The second metal ring and the third metal ring are disposed in the middle of the metal ring assembly. The processor is connected to the second metal ring and the third metal ring respectively, and is used to determine the time for the conductive ions to flow through the metal ring group based on the potential difference signal between the second metal ring and the third metal ring; the processor is also used to determine the flow rate of the fluid based on the time for the conductive ions to flow through the metal ring group, and to determine the flow rate of the fluid based on the flow rate and the size of the well.

2. The flow measurement device for oilfield production wells according to claim 1, characterized in that, There are two metal ring groups, which are disposed on the probe and at different distances from the port of the probe. The step of determining the flow rate of the fluid based on the time it takes for the conductive ions to flow through the metal ring assembly includes: The flow rate is determined based on the distance between the two metal ring groups and the time difference between the conductive ions flowing through the two metal ring groups.

3. The flow measurement device for oilfield production wells according to claim 1 or 2, characterized in that, The ring surface of each metal ring in the metal ring assembly is perpendicular to the line connecting the two ends of the probe.

4. The flow measurement device for oilfield production wells according to claim 3, characterized in that, The inner layer of the probe's frame is made of metal; the inner metal layer of the probe's frame is covered with an insulating layer, and an insulating sleeve is installed between each metal ring of the metal ring assembly.

5. The flow measurement device for oilfield production wells according to claim 4, characterized in that, Determining the flow rate of the fluid based on the flow velocity and the size of the well includes: The flow rate is determined based on the flow velocity and the wellbore diameter.

6. The flow measurement device for oilfield production wells according to claim 5, characterized in that, Also includes: Lantern-shaped; The lantern body is disposed at both ends of the probe to keep the probe in the middle position of the well when measuring the flow rate.

7. A method for measuring the flow rate of an oilfield production well, characterized in that, A flow measurement device for an oilfield production well includes: a probe, at least one metal ring assembly, a conductive ion injector, and a processor. The conductive ion injector is disposed at one end of the probe, wherein during measurement, the port of the probe closest to the conductive ion injector faces downwards. The metal ring assembly includes a first metal ring, a second metal ring, a third metal ring, and a fourth metal ring, each metal ring sequentially disposed on a line connecting the two ends of the probe, and the ring surface of each metal ring intersects the line connecting the two ends of the probe. The first and fourth metal rings are disposed at the two ends of the metal ring assembly, forming an electric field after power is supplied. The second and third metal rings are disposed in the middle of the metal ring assembly. The processor is connected to the second and third metal rings respectively. The method includes: The time it takes for the conductive ions to flow through the metal ring assembly is determined based on the potential difference signal between the second and third metal rings; wherein, when the probe is placed inside the well, the conductive ion ejector ejects the conductive ions to follow the fluid inside the well through the outside of the probe; The flow rate of the fluid is determined based on the time it takes for the conductive ions to flow through the metal ring assembly; The flow rate of the fluid is determined based on the flow velocity and the size of the well.

8. A flow measurement device for an oilfield production well, characterized in that, Includes memory used to store computer programs; A processor, configured to execute the computer program to implement the steps of the flow measurement method for oilfield production wells as described in claim 7.

9. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the steps of the flow measurement method for oilfield production wells as described in claim 7.

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