Horizontal well liquid production profile measurement method based on magnetic resonance multiphase flowmeter

Abstract

The present application relates to the technical field of oil field development, in particular to a horizontal well liquid production profile measurement method based on a magnetic resonance multiphase flowmeter. An inlet end of a magnetic resonance multiphase flowmeter is connected to an oil outlet end of a coiled tubing by means of a well control device at a wellhead, an outlet end of the magnetic resonance multiphase flowmeter is connected to an external transportation pipe, and an oil inlet end of the coiled tubing is arranged at a target interval of a horizontal well. The method comprises: using the magnetic resonance multiphase flowmeter to obtain the flow velocity of a produced liquid of the target interval; using the magnetic resonance multiphase flowmeter to obtain the phase holdup of the produced liquid of the target interval; on the basis of the flow velocity and the phase holdup of the produced liquid and the tubing diameter of the coiled tubing, calculating the fluid output of the target interval; repeating the described steps until measurement of the fluid output of all intervals of the horizontal well is completed; and matching the fluid output of each interval of the horizontal well with a measurement depth, so as to draw a liquid production profile of the horizontal well. The method can be used for solving the problems of current production logging technologies such as high cost, unstable accuracy and impact on production efficiency.

Description

Horizontal well fluid production profile detection method based on magnetic resonance multiphase flowmeter Technical Field

[0001] The present application relates to the technical field of oilfield development, and in particular to a method for detecting a horizontal well production fluid profile based on a magnetic resonance multiphase flowmeter. Background Art

[0002] Horizontal wells can increase the productivity of oil and gas wells and are suitable for exploiting low-permeability, low-pressure, and heavy oil reservoirs. They can achieve high production rates with fewer wells. In recent years, the number of newly drilled horizontal wells has increased annually both domestically and internationally. The evaluation of horizontal well production performance, particularly the monitoring of the segmented production of each fracturing stage and the main producing intervals, is becoming increasingly important for future horizontal well design, modification, and production management. While existing production logging technologies can generally meet production needs for evaluating vertical well production performance, their application to horizontal wells cannot fully resolve the problems that arise. For example, in horizontal wells completed with slotted liners, bypass flow is prone to occur in the annular space between the slotted liner and the formation, causing logging equipment to become unsuitable or even fail. In addition, due to the separation of oil, gas and water in the wellbore under the action of gravity, the flow pattern of the mixed fluid is complex and changeable. In addition, due to the long-distance undulation of the horizontal wellbore and other reasons, the horizontal flow production profile is extremely complex. This brings great difficulties to the evaluation of the production dynamics of such oil and gas wells using production logging technology. It is difficult to solve a series of problems such as the flow distribution of the fluid in the entire horizontal well section, the inflow point of oil, gas and water, the well section of the production fluid, and the contribution rate of the horizontal section to the total flow.

[0003] In the petroleum industry, with the increasing depletion of conventional oil and gas resources and the deepening development of unconventional oil and gas resources, the underground fluids encountered in oil drilling and production projects are primarily oil-water two-phase mixtures. Shale oil and heavy oil, as important unconventional oil and gas resources, exhibit severe emulsification, with long-term oil-in-water and water-in-oil phases within pipelines. This, coupled with sand production downhole, presents significant challenges to oil and gas measurement and analysis. Conventional production logging methods are unable to effectively measure the three-phase oil, gas, and water production in each section of a horizontal well.

[0004] Summary of the Invention

[0005] The purpose of the embodiments of the present application is to provide a method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter.

[0006] To achieve the above objectives, the present application provides a method for detecting a production profile of a horizontal well using a magnetic resonance multiphase flowmeter. The inlet end of the magnetic resonance multiphase flowmeter is connected to the oil outlet end of a coiled tubing via a well control device at the wellhead, and the outlet end of the magnetic resonance multiphase flowmeter is connected to an external transmission pipeline. The oil inlet end of the coiled tubing is located in a target layer of the horizontal well. The method for detecting a production profile of a horizontal well comprises:

[0007] A1. Use a magnetic resonance multiphase flowmeter to obtain the flow rate of the produced fluid in the target layer;

[0008] A2. Use a magnetic resonance multiphase flowmeter to obtain the phase holdup of the produced fluid in the target layer;

[0009] A3. Calculate the fluid production of the target layer based on the flow rate, phase holdup, and coiled tubing diameter of the produced fluid;

[0010] A4. Repeat steps A1 to A3 until the fluid production of all intervals in the horizontal well is measured.

[0011] A5. Match the fluid production of each layer of the horizontal well with the measured depth and draw the horizontal well fluid production profile.

[0012] In some embodiments of the present application, the magnetic resonance multiphase flowmeter has two operating modes: flow measurement mode and static measurement mode; the magnetic resonance multiphase flowmeter operating in the flow measurement mode is used to measure the flow rate of the produced fluid, and the magnetic resonance multiphase flowmeter operating in the static measurement mode is used to measure the phase content of the produced fluid.

[0013] In some embodiments of the present application, the magnetic resonance multiphase flowmeter includes a main pipeline and a bypass pipeline, and a magnetic resonance flowmeter probe is provided on the main pipeline; when the magnetic resonance multiphase flowmeter operates in a flow measurement mode, the main pipeline is open and the bypass pipeline is closed; when the magnetic resonance multiphase flowmeter operates in a static measurement mode, the bypass pipeline is open and part of the produced fluid is statically closed in the main pipeline.

[0014] In some embodiments of the present application, the magnetic resonance multiphase flowmeter also includes a first three-way valve and a second three-way valve, the first end of the first three-way valve is connected to one end of the main pipeline, the second end of the first three-way valve is connected to one end of the bypass pipeline, and the third end of the first three-way valve is connected to the inlet end of the magnetic resonance multiphase flowmeter; the first end of the second three-way valve is connected to the other end of the main pipeline, the second end of the second three-way valve is connected to the other end of the bypass pipeline, and the third end of the second three-way valve is connected to the outlet end of the magnetic resonance multiphase flowmeter.

[0015] In some embodiments of the present application, a temperature and pressure gauge is further provided on the main pipeline for measuring the temperature and pressure of the produced fluid passing through the main pipeline.

[0016] In some embodiments of the present application, the method for detecting a horizontal well fluid production profile further includes:

[0017] B1. Obtain the geothermal gradient of the target mining site;

[0018] B2. Derivation of the temperature of the oil inlet end of the coiled tubing based on the temperature of the produced fluid measured by the thermometer and pressure gauge, the flow rate of the produced fluid, and the geothermal gradient;

[0019] B3. Repeat steps B1 to B2 until the temperature of all layers in the horizontal well is measured.

[0020] B4. Match the temperature of each layer of the horizontal well with the measured depth and draw the horizontal well temperature profile;

[0021] B5. Obtaining a fluid production profile of the horizontal well under the influence of temperature based on the horizontal well temperature profile.

[0022] In some embodiments of the present application, the method for detecting a horizontal well fluid production profile further includes:

[0023] C1. Obtain the hydrostatic pressure of the vertical pipe section;

[0024] C2. Derivation of the pressure at the oil inlet of the coiled tubing based on the pressure of the produced fluid measured by the thermometer and pressure gauge and the hydrostatic pressure of the vertical pipe section;

[0025] C3. Repeat steps C1 to C2 until the pressure measurement of all layers in the horizontal well is completed;

[0026] C4. Match the pressure of each layer of the horizontal well with the measured depth and draw the horizontal well pressure profile;

[0027] C5. Obtaining a fluid production profile of the horizontal well under the influence of pressure based on the horizontal well pressure profile.

[0028] In some embodiments of the present application, the horizontal well production profile detection method further includes: determining the working time of the magnetic resonance multiphase flowmeter in the static measurement mode according to the variation cycle of the produced liquid phase content.

[0029] In some embodiments of the present application, the phase content includes water content; and the operating time of the magnetic resonance multiphase flowmeter in the static measurement mode is no more than 1 / 2 of the water content variation period.

[0030] In some embodiments of the present application, the phase holdup includes oil content, gas content, and water content; the calculation formula of the fluid production Q oil / gas / water is as follows: Q 油 / 气 / 水 =πr 2 *v*S 油 / 气 / 水 (1)

[0031] In formula (1), Q 油 / 气 / 水 represents oil production, gas production or water production, r represents the radius of the coiled tubing, S 油 / 气 / 水 Indicates the oil content, gas content or water content of the produced fluid in the target layer.

[0032] This application has at least the following beneficial effects:

[0033] This application utilizes a magnetic resonance multiphase flowmeter in conjunction with continuous tubing technology to complete the measurement of horizontal well production profiles at the wellhead, solving the problems of existing production logging technology, such as high cost, unstable accuracy, and impact on production timeliness.

[0034] Other features and advantages of the embodiments of the present application will be described in detail in the subsequent detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0035] The accompanying drawings are used to provide a further understanding of the embodiments of the present application and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present application but do not constitute a limitation on the embodiments of the present application. In the accompanying drawings:

[0036] FIG1 schematically shows an installation diagram of a magnetic resonance multiphase flowmeter according to an embodiment of the present application;

[0037] FIG2 schematically shows the internal structure of a magnetic resonance multiphase flowmeter according to an embodiment of the present application;

[0038] FIG3 schematically shows a flow chart of measuring a production profile of a horizontal well according to an embodiment of the present application;

[0039] FIG4 schematically shows a fluid production profile of an example horizontal well according to an embodiment of the present application. DETAILED DESCRIPTION

[0040] To make the purpose, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below in conjunction with the drawings in the embodiments of the present application. It should be understood that the specific implementation methods described herein are only used to illustrate and explain the embodiments of the present application and are not used to limit the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

[0041] It should be noted that if the embodiments of the present application involve directional indications (such as up, down, left, right, front, back, etc.), the directional indications are only used to explain the relative position relationship, movement status, etc. between the components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0042] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of the present application, the descriptions of "first", "second", etc. are only for descriptive purposes and cannot be understood as indicating or implying their relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features defined as "first" and "second" may explicitly or implicitly include at least one of such features. In addition, the technical solutions between the various embodiments can be combined with each other, but they must be based on the fact that they can be implemented by ordinary technicians in this field. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such a combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0043] Example 1

[0044] A method for detecting the production profile of a horizontal well using a magnetic resonance multiphase flowmeter is disclosed. The inlet of the magnetic resonance multiphase flowmeter is connected to the oil outlet of a coiled tubing through a well control device (a blowout preventer or a Christmas tree) at the wellhead (as shown in FIG1 ). The outlet of the magnetic resonance multiphase flowmeter is connected to an external transmission pipeline, with the oil inlet of the coiled tubing located in the target layer of the horizontal well. Specifically, after the downhole produced fluid flows to the wellhead through the coiled tubing, it flows directly from a surface pipeline through the multiphase flowmeter for measurement and testing, and is then transported externally through an external transmission pipeline.

[0045] The horizontal well fluid production profile detection method includes:

[0046] A1. Use a magnetic resonance multiphase flowmeter to obtain the flow rate of the produced fluid in the target layer;

[0047] A2. Use a magnetic resonance multiphase flowmeter to obtain the phase holdup of the produced fluid in the target layer;

[0048] Specifically, the magnetic resonance multiphase flowmeter has two working modes: flow measurement mode and static measurement mode; the magnetic resonance multiphase flowmeter working in the flow measurement mode is used to measure the flow rate of the produced fluid, and the magnetic resonance multiphase flowmeter working in the static measurement mode is used to measure the phase content of the produced fluid.

[0049] The internal structure of the magnetic resonance multiphase flowmeter is shown in Figure 2. The magnetic resonance multiphase flowmeter includes a main pipeline and a bypass pipeline. The main pipeline is equipped with a magnetic resonance flowmeter probe. When the magnetic resonance multiphase flowmeter operates in flow measurement mode, the main pipeline is open and the bypass pipeline is closed. When the magnetic resonance multiphase flowmeter operates in static measurement mode, the bypass pipeline is open, and part of the produced fluid is statically closed in the main pipeline. The two ends of the main pipeline and the bypass pipeline are respectively connected by two three-way valves, namely a first three-way valve and a second three-way valve. The first end of the first three-way valve is connected to one end of the main pipeline, the second end of the first three-way valve is connected to one end of the bypass pipeline, and the third end of the first three-way valve is connected to the inlet of the magnetic resonance multiphase flowmeter. The first end of the second three-way valve is connected to the other end of the main pipeline, the second end of the second three-way valve is connected to the other end of the bypass pipeline, and the third end of the second three-way valve is connected to the outlet of the magnetic resonance multiphase flowmeter.

[0050] A3. Calculate the fluid production of the target layer based on the flow rate, phase holdup, and coiled tubing diameter of the produced fluid;

[0051] Specifically, the phase holdup includes oil content, gas content and water content; the fluid production Q 油 / 气 / 水 The calculation formula is as follows: 油 / 气 / 水 =πr 2 *v*S 油 / 气 / 水 (1)

[0052] In formula (1), Q 油 / 气 / 水 represents oil production, gas production or water production, r represents the radius of the coiled tubing, S 油 / 气 / 水 Indicates the oil content, gas content or water content of the produced fluid in the target layer.

[0053] A4. Repeat steps A1 to A3 until the fluid production of all intervals in the horizontal well is measured.

[0054] A5. Match the fluid production of each layer of the horizontal well with the measured depth and draw the horizontal well fluid production profile.

[0055] Combined with the wellhead well control device and the installation of the magnetic resonance multiphase flowmeter, the specific drawing process of the horizontal well production profile can be seen in Figure 3. The specific measurement process is as follows:

[0056] Before starting measurement, the MRI equipment must be connected to the surface pipeline and switched to flow measurement mode (the main pipeline is open, allowing fluid to flow through the MRI probe, and the bypass pipeline is closed). Once the bottom of the coiled tubing is lowered into the target layer, measurement can begin.

[0057] After starting the measurement, the blowout preventer or Christmas tree is first opened to allow the downhole fluid to flow into the magnetic resonance multiphase flowmeter through the coiled tubing, blowout preventer or Christmas tree, and then flow into the surface manifold for further processing.

[0058] The magnetic resonance multiphase flowmeter first collects downhole produced fluid temperature, pressure, and flow rate information in real time in flow measurement mode. After a period of time, it switches to static measurement mode (the fluid in the probe is stationary, and the downhole produced fluid flows into the surface manifold through the magnetic resonance multiphase flowmeter's bypass). In static measurement mode, the magnetic resonance multiphase flowmeter is used to detect multiphase fluid properties such as phase holdup (water content, gas content, oil content), viscosity distribution, relaxation time, and density. The duration of the static measurement mode is determined by the change cycle of the produced fluid phase holdup. Typically, the operating time of the magnetic resonance multiphase flowmeter in static measurement mode is no more than 1 / 2 of the water content change cycle, in accordance with the sampling law (i.e., the sampling frequency is no less than twice the periodic change frequency of the measured parameter). Since the magnetic resonance multiphase flowmeter's operating mode switches between static and flow measurement, when the duration of the static measurement mode is determined, the duration of the flow measurement mode is also determined.

[0059] Based on the flow rate information and phase holdup information collected in dynamic and static modes, the flow rates of oil, gas and water phases can be derived. The specific method is flow rate Q 油 / 气 / 水 =πr2*v*S 油 / 气 / 水 , where r is the pipe radius, v is the flow velocity, and S is the phase holdup. Typically, the dynamic and static modes are switched repeatedly. After a single static mode measurement, the flowmeter switches to dynamic mode and cyclically measures for a period of time. The static mode measurement interval is determined by the frequency of changes in the fluid phase holdup. If the phase holdup changes over a long period of time, the static mode measurement interval can be set longer. The dynamic mode measurement frequency is generally the maximum acceptable frequency for the flowmeter, continuously monitoring the fluid flow rate.

[0060] After monitoring a layer, the valve connecting the wellhead blowout preventer or the multiphase flowmeter to the Christmas tree is closed. The coiled tubing drum rotates, dragging the bottom of the coiled tubing to the second measurement section. The above measurement steps are repeated to complete the measurement of the second measurement section.

[0061] Repeat the above steps until all horizontal well sections are measured. Then, the flow rate, fluid properties, temperature and pressure data of each layer can be obtained to draw the fluid production profile (as shown in Figure 4).

[0062] After the production profile test is completed, the multiphase flowmeter can be retained at the wellhead to be used for production measurement as needed.

[0063] Preferably, the horizontal well fluid production profile detection method further includes:

[0064] B1. Obtain the geothermal gradient of the target mining site;

[0065] B2. Derivation of the temperature of the oil inlet end of the coiled tubing based on the temperature of the produced fluid measured by the thermometer and pressure gauge, the flow rate of the produced fluid, and the geothermal gradient;

[0066] B3. Repeat steps B1 to B2 until the temperature of all layers in the horizontal well is measured.

[0067] B4. Match the temperature of each layer of the horizontal well with the measured depth and draw the horizontal well temperature profile;

[0068] B5. Obtaining a fluid production profile of the horizontal well under the influence of temperature based on the horizontal well temperature profile.

[0069] Temperature also factors influencing liquid production calculations. Considering temperature influences can lead to more accurate liquid production profiles for horizontal wells. For example, in steam-assisted gravity drainage (SAGD) wells, the temperature distribution in the horizontal section of the production well generally matches the liquid production distribution. High-temperature sections in horizontal wells indicate successful penetration of high-temperature steam, enabling viscosity reduction and oil drainage, and thus typically result in higher liquid production. Therefore, temperature profiles can, in some cases, confirm the accuracy of the obtained liquid production profile.

[0070] Preferably, the horizontal well fluid production profile detection method further includes:

[0071] C1. Obtain the hydrostatic pressure of the vertical pipe section;

[0072] C2. Derivation of the pressure at the oil inlet of the coiled tubing based on the pressure of the produced fluid measured by the thermometer and pressure gauge and the hydrostatic pressure of the vertical pipe section;

[0073] C3. Repeat steps C1 to C2 until the pressure measurement of all layers in the horizontal well is completed;

[0074] C4. Match the pressure of each layer of the horizontal well with the measured depth and draw the horizontal well pressure profile;

[0075] C5. Obtaining a fluid production profile of the horizontal well under the influence of pressure based on the horizontal well pressure profile.

[0076] Pressure also factors influencing liquid production calculations. Taking pressure into account yields a more accurate horizontal well production profile. Preferably, the pressure at the oil inlet of the coiled tubing can be further calculated by taking into account the pressure loss in the horizontal section to improve accuracy. Specifically, the pressure loss in the horizontal section is composed of four components: frictional pressure loss, acceleration pressure loss, mixing pressure loss, and potential pressure loss. Furthermore, since the gas phase is more affected by pressure than the oil, gas, and water phases, obtaining a pressure profile can significantly improve the accuracy of calculating the gas fraction in each section of the produced fluid.

[0077] It should also be noted that the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, commodity, or apparatus that includes a series of elements includes not only those elements but also other elements not explicitly listed, or includes elements inherent to such process, method, commodity, or apparatus. In the absence of further limitations, an element defined by the phrase "comprises a ..." does not exclude the presence of other identical elements in the process, method, commodity, or apparatus that includes the element.

[0078] The above are merely embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should all be included within the scope of the claims of the present application.

Claims

1. A method for detecting a production profile of a horizontal well based on a magnetic resonance multiphase flowmeter, wherein the inlet end of the magnetic resonance multiphase flowmeter is connected to the oil outlet end of a coiled tubing through a well control device at a wellhead, the outlet end of the magnetic resonance multiphase flowmeter is connected to an external transmission pipeline, and the oil inlet end of the coiled tubing is arranged at a target layer section of the horizontal well; characterized in that: The horizontal well production fluid profile detection method comprises: A1. Use a magnetic resonance multiphase flowmeter to obtain the flow rate of the produced fluid in the target layer; A2. Use a magnetic resonance multiphase flowmeter to obtain the phase content of the produced fluid in the target layer; A3. Calculate the fluid production of the target layer based on the flow rate, phase content and diameter of the coiled tubing of the produced fluid; A4. Repeat steps A1 to A3 until the fluid production of all layers of the horizontal well is measured; A5. Match the fluid production of each layer of the horizontal well with the measured depth and draw the horizontal well fluid production profile.

2. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 1, characterized in that: The magnetic resonance multiphase flowmeter has two working modes: Flow measurement mode, used to measure the flow rate of produced fluid; Static measurement mode is used to measure the phase content of produced fluid.

3. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 2, characterized in that: The magnetic resonance multiphase flowmeter comprises a main pipeline and a bypass pipeline, and a magnetic resonance flowmeter probe is arranged on the main pipeline; When the magnetic resonance multiphase flowmeter operates in the flow measurement mode, the main pipeline is open and the bypass pipeline is closed; When the magnetic resonance multiphase flowmeter operates in a static measurement mode, the pipeline passage is bypassed and part of the produced fluid is statically sealed in the main pipeline.

4. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 3, characterized in that: The magnetic resonance multiphase flowmeter also includes a first three-way valve and a second three-way valve; The first end of the first three-way valve is connected to one end of the main pipeline, the second end of the first three-way valve is connected to one end of the bypass pipeline, and the third end of the first three-way valve is connected to the inlet end of the magnetic resonance multiphase flowmeter; The first end of the second three-way valve is communicated with the other end of the main pipeline, the second end of the second three-way valve is communicated with the other end of the bypass pipeline, and the third end of the second three-way valve is connected to the outlet end of the magnetic resonance multiphase flowmeter.

5. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 3, characterized in that: The main pipeline is also provided with a temperature and pressure gauge for measuring the temperature and pressure of the produced fluid passing through the main pipeline.

6. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 5, characterized in that: The horizontal well production fluid profile detection method also includes: B1. Obtain the geothermal gradient of the target mining site; B2. Obtaining the temperature of the oil inlet end of the coiled tubing based on the temperature of the produced fluid, the flow rate of the produced fluid and the geothermal gradient measured by the thermometer and pressure gauge; B3. Repeat steps B1 to B2 until the temperature of all layers in the horizontal well is measured; B4. Match the temperature of each layer of the horizontal well with the measured depth and draw the temperature profile of the horizontal well; B5. Obtaining a fluid production profile of the horizontal well under the influence of temperature based on the horizontal well temperature profile.

7. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 5, characterized in that: The horizontal well production fluid profile detection method also includes: C1. Obtain the hydrostatic pressure of the vertical pipe section; C2. Based on the pressure of the produced fluid measured by the temperature and pressure gauge and the hydrostatic pressure of the vertical pipe section, deduce the pressure at the oil inlet end of the coiled tubing; C3, repeat steps C1 to C2 until the pressure measurement of all layers of the horizontal well is completed; C4. Match the pressure of each layer of the horizontal well with the measured depth and draw the pressure profile of the horizontal well; C5. Obtaining a fluid production profile of the horizontal well under the influence of pressure based on the horizontal well pressure profile.

8. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 5, characterized in that: The horizontal well production fluid profile detection method also includes: The working time of the magnetic resonance multiphase flowmeter in the static measurement mode is determined according to the variation cycle of the produced liquid phase content.

9. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 8, characterized in that: The phase content includes water content; the working time of the magnetic resonance multiphase flowmeter in the static measurement mode is not greater than 1 / 2 of the water content change period.

10. The method for detecting the production profile of a horizontal well based on a magnetic resonance multiphase flowmeter according to claim 1, characterized in that: The phase content includes oil content, gas content and water content; the fluid production Q 油 / 气 / 水 The calculation formula is as follows: 油 / 气 / 水 =πr 2 *v*S 油 / 气 / 水 (1) In formula (1), Q 油 / 气 / 水 represents oil production, gas production or water production, r represents the radius of the coiled tubing, S 油 / 气 / 水 Indicates the oil content, gas content or water content of the produced fluid in the target layer.

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