Method and device for calculating the holdup of each phase of fluids in a horizontal well

Abstract

The application provides a horizontal well phase fluid holdup calculation method and device, and belongs to the technical field of oil development. The method comprises the following steps: for any depth point on the wellbore, a plurality of static pressures in the wellbore cross section where the depth point is located are obtained; based on the plurality of static pressures in the wellbore cross section where the depth point is located, a static pressure distribution corresponding to the depth point is determined, the static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to a fluid flow line of the depth point and in the ground direction; based on the static pressure distribution corresponding to the depth point, a normalized height of a non-dominant phase fluid of the depth point is determined; and based on the normalized height of the non-dominant phase fluid of the depth point, phase fluid holdups in the depth point are calculated. The static pressure is not affected by fluid retention on the array probe, so that the calculated phase fluid holdups are more accurate and reliable.

Description

Technical Field

[0001] This invention relates to the field of petroleum development technology, specifically to a method for calculating the fluid holdup of each phase in a horizontal well, a device for calculating the fluid holdup of each phase in a horizontal well, a machine-readable storage medium, and an electronic device. Background Technology

[0002] As exploration and development deepens, domestic oilfield exploration and development are gradually shifting towards deep and ultra-deep unconventional and complex lithological reservoirs. Unlike conventional reservoirs, these reservoirs present significant development challenges, highlighting the issue of economic viability. To achieve economical development, the number of long-distance horizontal wells is increasing. Horizontal well production profile logging is an effective means of evaluating the reservoir production contribution of horizontal wells.

[0003] Currently, the theory of oil-water flow characteristics in horizontal wells generally focuses on several aspects: flow mode identification, flow mode conversion, effective viscosity, flow pressure drop estimation, phase reversal identification, droplet formation, and droplet size distribution. In practical applications, the main parameters used are pressure drop relative to flow velocity, fluid phase retention or accumulation, and thermal properties. Currently, in well logging interpretation, the interpretation and evaluation of horizontal well production profile data mainly involves obtaining the formation velocity of the fluid within the probe area using an array rotor, obtaining the oil-water phase holdup of the mixed fluid within the probe area using array holdup, and establishing a projection method using mathematical means to calculate the fluid formation velocity and phase holdup at the wellbore cross-section, thereby obtaining the apparent velocity of the oil and water phases and ultimately evaluating the reservoir's production status. However, currently, a certain number of horizontal wells in China have low production, poor wellbore environments, and complex fluid properties, leading to deviations in the response of array rotor and array holdup instruments during actual measurements. If one parameter fails to obtain a suitable measurement value, the interpretation process will be completely hindered, posing difficulties for interpretation and evaluation work. Meanwhile, existing methods for interpreting and evaluating horizontal well oil-water two-phase production profiles only measure the pressure, a key parameter for critical fluid flow, using a central instrument. Subsequent calculations only estimate the fluid's PVT properties, failing to measure the phase distribution across the wellbore cross-section and the pressure drop along the flow direction. This results in a lack of interpretation and evaluation based on the fundamental nature of fluid flow. Therefore, horizontal well oil-water two-phase flow still presents some problems, requiring additional methods to compensate for or replace existing interpretation and evaluation approaches.

[0004] Currently, there are several main methods for evaluating production profiles in horizontal wells. One is an interpretation and evaluation method based on a circular array rotor and array probe; the other is an evaluation method based on a triangularly distributed array rotor and array probe. Both methods are based on the characteristics of fluid formation flow, obtaining the holdup distribution on the vertical projection axis of the wellbore section perpendicular to the fluid flow direction through linear or polynomial fitting, and calculating the holdup of each fluid phase using volume integration.

[0005] However, under low production conditions, the above method fails to accurately reflect the distribution of the oil and water phases in the wellbore cross section because the medium-to-high viscosity fluid remains on the array probe, resulting in unreliable calculations of the holdup of each phase fluid. Summary of the Invention

[0006] The purpose of this invention is to provide a method for calculating the fluid holdup of each phase in a horizontal well, a device for calculating the fluid holdup of each phase in a horizontal well, a machine-readable storage medium, and an electronic device. This method for calculating the fluid holdup of each phase in a horizontal well yields more accurate and reliable results.

[0007] To achieve the above objectives, the first aspect of this application provides a method for calculating the fluid holdup of each phase in a horizontal well, comprising:

[0008] For any depth point on the wellbore, obtain multiple static pressures in the cross-section of the wellbore where the depth point is located;

[0009] Based on multiple static pressures in the cross-section of the wellbore where the depth point is located, the static pressure distribution corresponding to the depth point is determined. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface.

[0010] Based on the static pressure distribution corresponding to the depth point, the normalized height of the non-dominant phase fluid at the depth point is determined;

[0011] Based on the normalized height of the non-dominant phase fluid at the depth point, the fluid holding capacity of each phase at the depth point is calculated.

[0012] In this embodiment of the application, there are multiple detection points in the cross-section of the wellbore where the depth point is located, and each detection point corresponds to a static pressure;

[0013] The step of determining the static pressure projection distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore where the depth point is located includes:

[0014] A two-dimensional coordinate system is established, wherein the origin of the two-dimensional coordinate system is the center of the cross-section of the well barrel where the depth point is located, the Y-axis of the two-dimensional coordinate system is perpendicular to the fluid streamline and points towards the ground, and the positive direction of the X-axis is the direction in which the Y-axis of the two-dimensional coordinate system is rotated 90° clockwise around the circumference of the cross-section of the well barrel where the depth point is located.

[0015] Mark the position of each detection point in the two-dimensional coordinate system to obtain the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore.

[0016] Based on the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore and the corresponding static pressure, the static pressure distribution corresponding to the depth point is determined.

[0017] In this embodiment of the application, the step of marking the positions of each detection point in the two-dimensional coordinate system and obtaining the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore includes:

[0018] Mark the position of each detection point in the two-dimensional coordinate system to obtain the initial coordinates of each detection point;

[0019] The projection values ​​on the Y-axis of the initial coordinates of each detection point are normalized to obtain the normalized distance from each detection point to the center of the wellbore.

[0020] In this embodiment of the application, determining the normalized height of the non-dominant phase fluid at the depth point based on the hydrostatic pressure distribution corresponding to the depth point includes:

[0021] Based on the static pressure distribution corresponding to the depth point, the static pressure inflection point is determined;

[0022] Based on the static pressure inflection point, the normalized height of the non-dominant phase fluid at the depth point is determined.

[0023] In this embodiment of the application, the calculation of the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point includes:

[0024] Based on the normalized height of the non-dominant phase fluid at the depth point, the holdup of the non-dominant phase fluid at the depth point is calculated according to a preset fluid holdup calculation formula, which is:

[0025]

[0026] Where h is the normalized height of the non-dominant phase fluid at the depth point, and Y adv The holdup of the non-dominant phase fluid at the depth point is given by π, where π is the mathematical constant pi.

[0027] Based on the holdup of the non-dominant phase fluid at the depth point, the holdup of the dominant phase fluid at the depth point is calculated to obtain the holdup of each phase fluid at the depth point.

[0028] In this embodiment of the application, the method further includes:

[0029] Obtain well logging curves, which are curves showing the change of static pressure with the position of the detection point;

[0030] Based on the well logging curves, the expression for water holdup is determined.

[0031] Based on the water holdup expression, the water holdup distribution of the wellbore cross section at the depth point is determined.

[0032] In this embodiment of the application, the method further includes:

[0033] The total pressure, average pressure of each phase fluid, and wellbore temperature are obtained at each detection point in the cross-section of the wellbore where the depth point is located.

[0034] Based on the static pressure in the cross-section of the wellbore at the depth point and the total pressure at each detection point, the dynamic pressure at each detection point is calculated.

[0035] Based on the average pressure of each phase fluid and the wellbore temperature, the stratification density of each phase fluid in the wellbore environment is calculated;

[0036] Based on the dynamic pressure at each detection point and the stratification density of each phase fluid in the wellbore environment, the stratification velocity of each phase fluid at each detection point is obtained.

[0037] In this embodiment of the application, it also includes:

[0038] Based on the location of each detection point and the corresponding stratification velocity of each phase fluid, the velocity profile inside the wellbore is obtained.

[0039] In this embodiment of the application, before obtaining the multiple static pressures in the cross-section of the wellbore where the depth point is located, the method further includes:

[0040] Obtain the initial logging curve, which is the curve of the static pressure in the cross section of the wellbore at the depth point changing with the position of the detection point;

[0041] The initial logging curve is then repositioned to its depth to obtain the final logging curve.

[0042] A second aspect of this application provides a device for calculating the fluid holdup of each phase in a horizontal well, comprising:

[0043] The acquisition module is used to acquire multiple static pressures in the cross-section of the wellbore at any depth point on the wellbore.

[0044] A module is established to determine the static pressure distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore where the depth point is located. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface.

[0045] The determination module is used to determine the normalized height of the non-dominant phase fluid at the depth point based on the static pressure distribution corresponding to the depth point;

[0046] The calculation module is used to calculate the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point.

[0047] A third aspect of this application provides an electronic device, the electronic device comprising:

[0048] At least one processor;

[0049] A memory connected to the at least one processor;

[0050] The memory stores instructions that can be executed by the at least one processor, which implements the above-described method for calculating the fluid holdup of each phase in a horizontal well by executing the instructions stored in the memory.

[0051] A fourth aspect of this application provides a machine-readable storage medium storing instructions that, when executed by a processor, configure the processor to perform the above-described method for calculating the fluid holdup of each phase in a horizontal well.

[0052] Through the above technical solution, for any depth point in the wellbore, multiple static pressures in the cross-section of the wellbore at the depth point are obtained; based on the multiple static pressures in the cross-section of the wellbore at the depth point, the static pressure distribution corresponding to the depth point is determined, and the static pressure distribution corresponding to the depth point is the static pressure projection distribution perpendicular to the fluid streamlines at the depth point and towards the ground surface; based on the static pressure distribution corresponding to the depth point, the normalized height of the non-dominant phase fluid at the depth point is determined; based on the normalized height of the non-dominant phase fluid at the depth point, the fluid holdup of each phase at the depth point is calculated. By using multiple static pressures in the wellbore cross-section, the static pressure distribution perpendicular to the fluid streamlines at the depth point and towards the ground surface can be determined, and the normalized height of the non-dominant phase fluid along the fluid streamlines perpendicular to the depth point and towards the ground surface can be determined quickly and accurately. Then, based on the normalized height of the non-dominant phase fluid, the fluid holdup of each phase can be calculated quickly and accurately. This method is obtained through static pressure calculation. Static pressure is not affected by fluid retention on the array probe, and therefore does not affect the fluid holdup of each phase, making the calculated fluid holdup of each phase more accurate and reliable.

[0053] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0054] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0055] Figure 1 The illustration shows a flowchart of a method for calculating the fluid holdup of each phase in a horizontal well according to an embodiment of this application;

[0056] Figure 2 A schematic diagram illustrating typical characteristics of simulated wellbore fluid distribution according to embodiments of this application is shown.

[0057] Figure 3 A schematic diagram illustrating the static pressure distribution according to an embodiment of this application is shown.

[0058] Figure 4 This diagram illustrates the relationship between static pressure change and water holding capacity according to an embodiment of the present application.

[0059] Figure 5 A schematic diagram illustrating the wellbore cross-sectional holdup distribution according to an embodiment of this application is shown.

[0060] Figure 6 A schematic diagram illustrating velocity profiles of various phase fluids according to embodiments of this application is shown.

[0061] Figure 7 This illustration schematically shows a flow chart of a pressure parameter-based evaluation method according to an embodiment of this application;

[0062] Figure 8 This schematic diagram illustrates the structure of a horizontal well fluid holdup calculation device according to an embodiment of this application;

[0063] Figure 9 The diagram illustrates the internal structure of a computer device according to an embodiment of this application.

[0064] Explanation of reference numerals in the attached figures

[0065] 410 - Acquisition Module; 420 - Establishment Module; 430 - Determination Module; 440 - Calculation Module; A01 - Processor; A02 - Network Interface; A03 - Internal Memory; A04 - Display Screen; A05 - Input Device; A06 - Non-volatile Storage Medium; B01 - Operating System; B02 - Computer Program. Detailed Implementation

[0066] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of the present invention.

[0067] It should be noted that the acquisition, transmission, storage, use, and processing of data in the technical solution of this application all comply with the relevant provisions of national laws and regulations. In the embodiments of this application, certain existing industry solutions such as software, components, and models may be mentioned. These should be considered exemplary, intended only to illustrate the feasibility of implementing the technical solution of this application, and do not imply that the applicant has already used or necessarily used such solutions.

[0068] It should be noted that if the embodiments of this application involve directional indicators (such as up, down, left, right, front, back, etc.), the directional indicators are only used to explain the relative positional relationship and movement of the components in a certain specific posture (as shown in the figure). If the specific posture changes, the directional indicators will also change accordingly.

[0069] Furthermore, if the embodiments of this application involve descriptions such as "first" or "second," these descriptions are for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, features defined with "first" or "second" may explicitly or implicitly include at least one of those features. Additionally, the technical solutions of various embodiments can be combined with each other, but this must be based on the ability of those skilled in the art to implement them. If the combination of technical solutions is contradictory or impossible to implement, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed in this application.

[0070] Please refer to Figure 1 , Figure 1 The illustration schematically shows a flowchart of a method for calculating the fluid holdup of each phase in a horizontal well according to an embodiment of this application. This embodiment provides a method for calculating the fluid holdup of each phase in a horizontal well, including the following steps:

[0071] Step 210: For any depth point on the wellbore, obtain multiple static pressures in the cross-section of the wellbore where the depth point is located;

[0072] In this embodiment, there can be multiple depth points along the wellbore of a horizontal well. For any given depth point, transversely cutting the wellbore along that depth point yields multiple wellbore cross-sections, with each depth point corresponding to a specific cross-section. Within each wellbore cross-section, multiple detection points can be set up, each equipped with a probe. The probes measure the pressure at various points within the wellbore in real time, thereby obtaining multiple static pressures within the wellbore cross-section at each depth point. In specific implementation, this can be achieved by collecting logging data that conforms to quality specifications. This logging data includes multiple static pressures; for example, it can be logging data conforming to the SY / T5132-2012 "Quality Specification for Petroleum Logging Raw Data" standard, thereby obtaining multiple static pressures and the total fluid height within the wellbore cross-section at each depth point.

[0073] Step 220: Based on multiple static pressures in the cross-section of the wellbore where the depth point is located, determine the static pressure distribution corresponding to the depth point. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and directed toward the ground surface.

[0074] In this embodiment, each static pressure corresponds to a detection point. Based on the location of each static pressure corresponding to a detection point, the fluid streamline perpendicular to the depth point and the static pressure projection distribution towards the ground can be obtained.

[0075] In some embodiments, there are multiple detection points in the cross-section of the wellbore where the depth point is located, and each detection point corresponds to a static pressure; accordingly, determining the static pressure distribution corresponding to the depth point based on the multiple static pressures in the cross-section of the wellbore where the depth point is located includes the following steps:

[0076] First, a two-dimensional coordinate system is established, wherein the origin of the two-dimensional coordinate system is the center of the cross-section of the well barrel where the depth point is located, the Y-axis of the two-dimensional coordinate system is perpendicular to the fluid streamline and points towards the ground, and the positive direction of the X-axis is the direction in which the Y-axis of the two-dimensional coordinate system is rotated 90° clockwise around the circumference of the cross-section of the well barrel where the depth point is located.

[0077] In this embodiment, a two-dimensional coordinate system is established along the horizontal direction of the fluid streamlines and in the direction perpendicular to the streamlines and pointing towards the ground. Please refer to [link / reference needed]. Figure 2 , Figure 2 The diagram illustrates typical characteristics of simulated wellbore fluid distribution according to an embodiment of this application. The center of the wellbore cross-section is the zero point, the direction perpendicular to the streamlines towards the ground is the Y-axis, and the positive direction of the X-axis is the direction of the Y-axis rotated 90° clockwise around the circumference of the wellbore cross-section.

[0078] Then, the positions of each detection point are marked in the two-dimensional coordinate system to obtain the distance from the center of the wellbore after the projection of each detection point onto the Y-axis.

[0079] In this embodiment, each detection point has corresponding coordinates in a two-dimensional coordinate system, wherein the Y-axis coordinate of each detection point is the normalized distance of the Y-axis projection of the detection point to the center of the wellbore.

[0080] Finally, based on the normalized distance of each detection point projected onto the Y-axis from the wellbore center and the corresponding static pressure, the static pressure distribution corresponding to the depth point is determined.

[0081] In this embodiment, each static pressure corresponds to a normalized distance from the projection of a detection point onto the Y-axis to the center of the wellbore, thereby obtaining the static pressure distribution corresponding to the depth point.

[0082] By first constructing a two-dimensional coordinate system, then marking the position of each detection point in the two-dimensional coordinate system, and then quickly determining the static pressure distribution corresponding to the depth point based on the distance from each detection point to the center of the wellbore and the corresponding static pressure.

[0083] In some embodiments, marking the positions of each detection point in the two-dimensional coordinate system and obtaining the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore includes the following steps:

[0084] The first step is to mark the position of each detection point in the two-dimensional coordinate system to obtain the initial coordinates of each detection point;

[0085] In this embodiment, the positions of each detection point can be marked in a two-dimensional coordinate system first.

[0086] The second step is to normalize the projection values ​​on the Y-axis of the initial coordinates of each detection point to obtain the normalized distance from the projection of each detection point on the Y-axis to the center of the wellbore.

[0087] In this embodiment, each pressure probe has a two-dimensional coordinate system, i.e., the initial coordinates of the detection point, which can be represented as (x... i ,y i ), then y i The normalized distance from the center of the wellbore, projected onto the Y-axis, can be obtained by substituting the Y-axis values ​​from the initial coordinates of each detection point into the conversion formula, which is: Among them, R (Norm)i R represents the normalized distance projection of each pressure probe onto the Y-axis, i.e., the normalized distance from each probe point projected onto the Y-axis to the center of the wellbore, which is the distance from each probe point to the center of the wellbore. yi R is the Y-axis coordinate of the detection point in the two-dimensional coordinate system, that is, the value on the Y-axis in the initial coordinates of the detection point, and R is the radius of the wellbore.

[0088] By converting the values ​​on the Y-axis in the initial coordinates of each detection point into projected values ​​on the Y-axis, the values ​​on the Y-axis in the initial coordinates are normalized, so that the distances from each detection point projected onto the Y-axis to the center of the wellbore are normalized values, which facilitates calculation.

[0089] Step 230: Based on the static pressure distribution corresponding to the depth point, determine the normalized height of the non-dominant phase fluid at the depth point;

[0090] In this embodiment, in a multiphase flow system, there is a close relationship between static pressure distribution and phase interfaces as well as the height of each phase fluid. For stratified multiphase flow, in the horizontal direction, the pressure balance between different phases is determined by gravity and the shape of the phase interfaces. Therefore, the height of each phase fluid at a depth point can be determined by the static pressure distribution.

[0091] In some embodiments, determining the normalized height of the non-dominant phase fluid at the depth point based on the hydrostatic pressure distribution corresponding to the depth point includes the following steps:

[0092] First, based on the static pressure distribution corresponding to the depth point, the static pressure inflection point is determined;

[0093] In this embodiment, please refer to Figure 3 , Figure 3 The diagram illustrates a static pressure distribution according to an embodiment of this application. In a horizontal well laminar flow mode, due to the density difference between the oil and water phases, there is an inflection point in the static pressure along the Y-axis. The static pressure inflection point can refer to the point in the static pressure distribution where the static pressure suddenly increases or decreases.

[0094] Then, based on the static pressure inflection point, the normalized height of the non-dominant phase fluid at the depth point is determined;

[0095] In this embodiment, the static pressure inflection point on the Y-axis represents the height of the non-dominant phase fluid (the fluid occupying a relatively small portion of the wellbore cross-section) in the oil-water two-phase system, which can be expressed as R. (Norm) Given that the distances from each detection point to the wellbore center are normalized values, the normalized value of the hydrostatic inflection point on the Y-axis is correspondingly the normalized height of the non-dominant phase fluid (the fluid occupying a relatively small portion of the wellbore cross-section) in the oil-water two-phase system. Then, subtracting the normalized height of the non-dominant phase fluid from the normalized diameter of the cross-sectional circle yields the normalized height of the dominant phase fluid.

[0096] The variation of static pressure along the direction of gravity on the wellbore cross-section reflects the height occupied by each fluid phase in the wellbore cross-section. The change in static pressure inflection point is basically consistent with the height of the fluid interface in oil-water stratified flow. The height of each of the oil and water phases can be quickly and accurately determined by the location of the static pressure inflection point. By determining the static pressure inflection point based on the static pressure distribution corresponding to the depth point, the normalized height of the non-dominant phase fluid can be quickly determined.

[0097] Step 240: Calculate the holding capacity of each phase fluid at the depth point based on the normalized height of the non-dominant phase fluid at the depth point.

[0098] In this embodiment, the above-mentioned calculation of the fluid holdup of each phase can be performed by first calculating the holdup of the non-dominant phase fluid, and then calculating the holdup of the dominant phase fluid based on the fact that the holdup of the non-dominant phase fluid and the holdup of the dominant phase fluid are both equal. Alternatively, the above-mentioned calculation of the fluid holdup of each phase can be performed by using the normalized height of the non-dominant phase fluid at the depth point and the normalized diameter of the cross-sectional circle to calculate the normalized height of the dominant phase fluid, and then calculating the holdup of the dominant phase fluid.

[0099] In some embodiments, for ease of calculation, the calculation of the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point includes the following steps:

[0100] First, based on the normalized height of the non-dominant phase fluid at the depth point, the holdup of the non-dominant phase fluid at the depth point is calculated according to a preset fluid holdup calculation formula, which is:

[0101]

[0102] Where h is the normalized height of the non-dominant phase fluid at the depth point, and Y adv The holdup of the non-dominant phase fluid at the depth point is given by π, where π is the mathematical constant pi.

[0103] Then, based on the holdup of the non-dominant phase fluid at the depth point, the holdup of the dominant phase fluid at the depth point is calculated to obtain the holdup of each phase fluid at the depth point.

[0104] In this embodiment, the wellbore cross-sectional area occupied by the non-dominant phase fluid at the depth point can be calculated based on the normalized height of the non-dominant phase fluid. The calculation formula is as follows:

[0105] Where R is the wellbore radius, h is the normalized height of the non-dominant phase fluid at depth, and S... adv This refers to the cross-sectional area of ​​the wellbore occupied by that phase. The holdup is the ratio of the cross-sectional area occupied by each phase of fluid to the total cross-sectional area of ​​the wellbore, i.e. After substituting and simplifying the above formula, we can obtain... After determining the normalized height of the non-dominant phase fluid at the depth point, substituting the normalized height of the non-dominant phase fluid at each depth point into the above formula yields the corresponding fluid holdup. After calculating the holdup of the non-dominant phase fluid, subtracting the holdup of the non-dominant phase fluid from 1 gives the holdup of the dominant phase fluid, thus obtaining the holdup of each phase fluid at the depth point.

[0106] For example: the normalized height of the non-dominant phase fluid is R. Norm Then, substituting into the above formula, This allows us to obtain the fluid holdup of the non-dominant phase fluid.

[0107] In the above implementation process, for any depth point on the wellbore, multiple static pressures in the cross-section of the wellbore at the depth point are acquired. Based on these multiple static pressures, the static pressure distribution corresponding to the depth point is determined. This static pressure distribution is the static pressure projection distribution perpendicular to the fluid streamlines at the depth point and directed towards the ground surface. Based on this static pressure distribution, the normalized height of the non-dominant phase fluid at the depth point is determined. Based on the normalized height of the non-dominant phase fluid at the depth point, the fluid holdup of each phase at the depth point is calculated. By using multiple static pressures in the wellbore cross-section, the static pressure distribution perpendicular to the fluid streamlines at the depth point and directed towards the ground surface can be determined. This allows for the rapid and accurate determination of the normalized height of the non-dominant phase fluid along the fluid streamlines perpendicular to the depth point and directed towards the ground surface. Then, based on the normalized height of the non-dominant phase fluid, the fluid holdup of each phase can be calculated quickly and accurately. This method is based on static pressure calculations, which are unaffected by fluid stagnation on the array probes, thus not affecting the fluid holdup of each phase, making the calculated fluid holdup of each phase more accurate and reliable.

[0108] In some embodiments, the method further includes the following steps:

[0109] First, obtain the logging curve, which is the curve of static pressure changing with the position of the detection point;

[0110] In this embodiment, a curve can be fitted based on each static pressure and the corresponding detection point position. If this curve has an inflection point, then it must be a two-phase fluid of oil and water; if it does not have an inflection point, then it is a single-phase oil or a single-phase water.

[0111] Then, based on the well logging curves, the expression for water holdup is determined;

[0112] In this embodiment, if it is a two-phase fluid of oil and water, the water holdup can be calculated first, and then the oil holdup can be calculated. Please refer to [link / reference needed]. Figure 4 , Figure 4 The illustration schematically depicts the relationship between static pressure change and water holding capacity according to an embodiment of this application. The aforementioned water holding capacity expression can be established using the static pressure value projected onto the Y-axis and the distance, forming a fourth-order polynomial relationship with the water holding capacity. This fourth-order polynomial relationship is as follows:

[0113]

[0114] in, For water holding capacity, Let be the rate of change of pressure projected onto the direction of gravity, i be the index of the projection point on the direction of gravity, and A1, A2, A3, A4, and A5 be constants. ΔP yiLet ΔR be the static pressure change value at any projection point in the well logging curve along the direction of gravity. (Norm)i This represents the change in distance along the direction of gravity for any projection point in the logging curve.

[0115] Finally, based on the water holdup expression, the water holdup distribution of the wellbore cross section at the depth point is determined.

[0116] In this embodiment, based on the above expression, substituting the static pressure change and distance change values ​​of each detection point into the formula, the water holding capacity corresponding to each projection point in the gravity direction can be obtained. After obtaining the water holding capacity, the oil holding capacity can be calculated based on the fact that the sum of the water holding capacity and the oil holding capacity is 1. Then, the water holding capacity at the highest point in the positive gravity direction is defined as the minimum value, and the water holding capacity at the lowest point in the gravity direction is defined as the maximum value. Based on the water holding capacity corresponding to each projection point in the gravity direction, the water holding capacity distribution of the wellbore cross-section is obtained by fitting a curve. Please refer to... Figure 5 , Figure 5 A schematic diagram illustrating the wellbore cross-sectional holdup distribution according to an embodiment of this application is shown.

[0117] By acquiring well logging curves, which are curves showing the change of static pressure with the position of the detection point, and based on the rate of change of static pressure projected onto the gravity direction in the well logging curves, the water holdup expression can be accurately obtained. Furthermore, based on the water holdup expression, the water holdup distribution of the wellbore cross section at the depth point can be obtained accurately and reliably.

[0118] In some embodiments, the method further includes the following steps:

[0119] First, obtain the total pressure, average pressure of each phase fluid, and wellbore temperature at each detection point in the cross-section of the wellbore where the depth point is located;

[0120] In this embodiment, the total pressure, average pressure of each phase fluid, and wellbore temperature at each detection point in the cross-section of the wellbore where the aforementioned depth point is located can all be obtained by collecting logging data.

[0121] Then, based on the static pressure in the cross-section of the wellbore where the depth point is located and the total pressure at each detection point, the dynamic pressure at each detection point is calculated.

[0122] In this embodiment, the static pressures and total pressures at the wellbore cross-section at the specified depth are measured by instruments, and the dynamic pressure is calculated from the total pressure and static pressure using the following formula: P D =P T -P S , where P D For dynamic pressure, P S For static pressure, P T For total pressure.

[0123] Then, based on the average pressure of each phase fluid and the wellbore temperature, the stratification density of each phase fluid in the wellbore environment is calculated;

[0124] In this embodiment, the oil-water two-phase fluid stratification density is calculated, and the oil-water density in the wellbore environment can be reconstructed based on regional fluid data. The formula for calculating the water phase density in the wellbore environment is: Where, ρ w The density of the water phase in the wellbore environment. The average pressure of the aqueous phase layer is T, and the wellbore temperature is T. The density is a temperature-pressure function and can be obtained from multiple sets of data. The oil phase density can be calculated using the same method as the water phase density, which will not be elaborated here.

[0125] Finally, based on the dynamic pressure at each detection point and the stratification density of each phase fluid in the wellbore environment, the stratification velocity of each phase fluid at each detection point is obtained.

[0126] In this embodiment, the fluid stratification velocity can be determined using dynamic pressure, and the relationship between velocity and dynamic pressure is as follows: Where ν is the fluid stratification velocity and ρ is the fluid stratification density, the oil-water fluid density and dynamic pressure can be substituted into the above formula to calculate the oil-water fluid stratification velocity respectively.

[0127] By calculating the dynamic pressure at each detection point based on the static pressure at each point in the wellbore cross-section at the specified depth and the total pressure at each detection point, the dynamic pressure at each detection point is calculated. Based on the dynamic pressure at each detection point and the stratification density of each phase fluid in the wellbore environment, the stratification velocity of each phase fluid at each detection point is obtained. Dynamic pressure reflects the pressure in the direction of fluid flow and is the driving force for fluid movement along streamlines. It can determine the flow velocity of the stratified fluid. By combining multiple dynamic pressure parameters with temperature parameters, the stratified fluid density and stratification velocity can be organically combined, enabling reliable calculation of the oil-water two-phase fluid velocity in horizontal wells. Under the premise of fully considering the characteristic parameters of stratified flow, accurately calculating wellbore holdup and fluid velocity using array pressure parameters combined with temperature information contributes to the accurate evaluation of horizontal well production profiles.

[0128] In some embodiments, the method further includes obtaining a velocity profile of the fluid inside the wellbore based on the location of each detection point and the corresponding stratification velocity of each phase fluid.

[0129] In this embodiment, please refer to Figure 6 , Figure 6A schematic diagram of the velocity profiles of each phase fluid according to an embodiment of this application is shown. The fluid velocity at the pipe wall can be constrained to a constant value of 0. The velocity profile of the stratified fluid is established by projecting the obtained velocity in the direction of gravity. That is, each detection point in the direction of gravity corresponds to the velocity of the stratified fluid. Constructing the velocity profile of the fluid inside the wellbore helps to accurately evaluate the production profile of the horizontal well.

[0130] In some embodiments, prior to obtaining multiple static pressures in the cross-section of the wellbore where the depth point is located, the method further includes:

[0131] First, an initial logging curve is obtained, which is the curve of the static pressure in the cross-section of the wellbore at the depth point changing with the position of the detection point;

[0132] Then, the initial logging curve is repositioned to the depth to obtain the logging curve.

[0133] In this embodiment, depth correction of the logging curve can be performed based on completion logging data and casing coupling data, using natural gamma and coupling information for depth correction, which helps to accurately determine the location of each depth point.

[0134] In some embodiments, regional fluid information may also be collected, including information such as formation water salinity, crude oil density and viscosity at different temperatures and pressures, and gas-oil ratio.

[0135] The following examples illustrate the solution; please refer to them. Figure 7 , Figure 7 The schematic diagram illustrates a pressure parameter-based evaluation method according to an embodiment of this application. The specific process includes the following steps:

[0136] Step 101: Collect logging data that meets the quality specifications. The logging data includes logging curves.

[0137] Step 102: Perform depth correction and preprocessing on the logging curves, and define the properties of the well fluid.

[0138] Step 103: Establish a two-dimensional coordinate system along the horizontal direction (X-axis) perpendicular to the fluid streamlines and the direction pointing towards the ground (Y-axis) perpendicular to the streamlines. With the center of the wellbore cross-section as the zero point, normalize the distance of the Y-axis.

[0139] Step 104: Extract the dynamic and static pressure data within the calculation segment and reconstruct the distribution of dynamic and static pressure projected onto the Y-axis.

[0140] Step 105: Determine the inflection point of the static pressure on the Y-axis projection and determine the normalized height of the oil-water two-phase liquid level occupying the wellbore.

[0141] Step 106: Calculate the wellbore section holdup of the oil-water two-phase system and construct the wellbore section holdup distribution.

[0142] Step 107: Calculate the wellbore fluid density based on the temperature and pressure function of oil and water.

[0143] Step 108: Calculate the velocity of the oil-water two-phase separation using the relationship between dynamic pressure, density, and velocity.

[0144] Step 109: Constrain the velocity at the pipe wall to 0, and reconstruct the velocity profile of the oil-water two-phase system based on the obtained velocity.

[0145] Figure 1 This is a flowchart illustrating the method for calculating the fluid holdup of each phase in a horizontal well, as illustrated in this embodiment. It should be understood that, although... Figure 1 The steps in the flowchart are shown sequentially as indicated by the arrows, but these steps are not necessarily executed in the order indicated by the arrows. Unless otherwise specified herein, there is no strict order in which these steps are executed, and they can be performed in other orders. Figure 1 At least some of the steps in the process may include multiple sub-steps or multiple stages. These sub-steps or stages are not necessarily completed at the same time, but can be executed at different times. The execution order of these sub-steps or stages is not necessarily sequential, but can be executed in turn or alternately with other steps or at least some of the sub-steps or stages of other steps.

[0146] Please refer to Figure 8 , Figure 8 This schematically illustrates a structural diagram of a horizontal well fluid holdup calculation device according to an embodiment of the present application. This embodiment provides a horizontal well fluid holdup calculation device, including an acquisition module 410, an establishment module 420, a determination module 430, and a calculation module 440, wherein:

[0147] The acquisition module 410 is used to acquire multiple static pressures in the cross-section of the wellbore where any depth point is located for any depth point on the wellbore.

[0148] A module 420 is established to determine the static pressure distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore where the depth point is located. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface.

[0149] The determination module 430 is used to determine the normalized height of the non-dominant phase fluid at the depth point based on the static pressure distribution corresponding to the depth point;

[0150] The calculation module 440 is used to calculate the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point.

[0151] The horizontal well fluid holdup calculation device includes a processor and a memory. The acquisition module 410, establishment module 420, determination module 430 and calculation module 440 are all stored in the memory as program units. The processor executes the program units stored in the memory to realize the corresponding functions.

[0152] The processor contains a kernel, which retrieves the corresponding program units from memory. One or more kernels can be configured, and by adjusting kernel parameters, reliable calculations of the fluid holdup in each phase of a horizontal well can be achieved.

[0153] The memory may include non-permanent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM, and the memory includes at least one memory chip.

[0154] This invention provides a machine-readable storage medium storing a program that, when executed by a processor, implements the method for calculating the fluid holdup of each phase in a horizontal well.

[0155] This invention provides a processor for running a program, wherein the program executes the method for calculating the fluid holdup of each phase in a horizontal well.

[0156] In one embodiment, a computer device is provided, which may be a terminal, and its internal structure diagram may be as follows: Figure 9 As shown in the figure, the computer device includes a processor A01, a network interface A02, a display screen A04, an input device A05, and a memory (not shown) connected via a system bus. The processor A01 provides computing and control capabilities. The memory includes internal memory A03 and a non-volatile storage medium A06. The non-volatile storage medium A06 stores an operating system B01 and a computer program B02. The internal memory A03 provides an environment for the operation of the operating system B01 and the computer program B02 stored in the non-volatile storage medium A06. The network interface A02 is used for communication with external terminals via a network connection. When the computer program is executed by the processor A01, it implements a method for calculating the fluid holdup of each phase in a horizontal well. The display screen A04 can be a liquid crystal display (LCD) or an e-ink display. The input device A05 can be a touch layer covering the display screen, buttons, a trackball, or a touchpad mounted on the computer device casing, or an external keyboard, touchpad, or mouse.

[0157] Those skilled in the art will understand that Figure 9 The structure shown is merely a block diagram of a portion of the structure related to the present application and does not constitute a limitation on the computer device to which the present application is applied. Specific computer devices may include more or fewer components than those shown in the figure, or combine certain components, or have different component arrangements.

[0158] In one embodiment, the apparatus for calculating the fluid holdup of each phase in a horizontal well provided in this application can be implemented as a computer program, which can be implemented in various ways, such as... Figure 9 The computer device shown runs on this device. The computer device's memory can store the various program modules that make up the apparatus for calculating the fluid holdup of each phase in this horizontal well, for example, Figure 8 The diagram shows the acquisition module 410, the establishment module 420, the determination module 430, and the calculation module 440. The computer program comprised of these modules causes the processor to execute the steps in the horizontal well fluid holdup calculation methods of the various embodiments of this application described in this specification.

[0159] Figure 9 The computer device shown can be used as follows Figure 8 The acquisition module 410 in the apparatus for calculating the fluid holdup of each phase in a horizontal well, as shown, executes step 210. A computer device can execute step 220 via the establishment module 420. A computer device can execute step 230 via the determination module 430. A computer device can execute step 240 via the calculation module 440.

[0160] This application provides an electronic device comprising: at least one processor; and a memory connected to the at least one processor; wherein the memory stores instructions executable by the at least one processor, and the at least one processor implements the above-described method for calculating the fluid holdup of each phase in a horizontal well by executing the instructions stored in the memory. When the processor executes the instructions, it performs the following steps:

[0161] For any depth point on the wellbore, obtain multiple static pressures in the cross-section of the wellbore where the depth point is located;

[0162] Based on multiple static pressures in the cross-section of the wellbore where the depth point is located, the static pressure distribution corresponding to the depth point is determined. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface.

[0163] Based on the static pressure distribution corresponding to the depth point, the normalized height of the non-dominant phase fluid at the depth point is determined;

[0164] Based on the normalized height of the non-dominant phase fluid at the depth point, the fluid holding capacity of each phase at the depth point is calculated.

[0165] In one embodiment, there are multiple detection points in the cross-section of the wellbore where the depth point is located, and each detection point corresponds to a static pressure.

[0166] The step of determining the static pressure distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore at the depth point includes:

[0167] A two-dimensional coordinate system is established, wherein the origin of the two-dimensional coordinate system is the center of the cross-section of the well barrel where the depth point is located, the Y-axis of the two-dimensional coordinate system is perpendicular to the fluid streamline and points towards the ground, and the positive direction of the X-axis is the direction in which the Y-axis of the two-dimensional coordinate system is rotated 90° clockwise around the circumference of the cross-section of the well barrel where the depth point is located.

[0168] Mark the position of each detection point in the two-dimensional coordinate system to obtain the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore.

[0169] Based on the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore and the corresponding static pressure, the static pressure distribution corresponding to the depth point is determined.

[0170] In one embodiment, marking the positions of each detection point in the two-dimensional coordinate system to obtain the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore includes:

[0171] Mark the position of each detection point in the two-dimensional coordinate system to obtain the initial coordinates of each detection point;

[0172] The projection values ​​on the Y-axis of the initial coordinates of each detection point are normalized to obtain the normalized distance from the projection of each detection point on the Y-axis to the center of the wellbore.

[0173] In one embodiment, determining the normalized height of the non-dominant phase fluid at the depth point based on the hydrostatic pressure distribution corresponding to the depth point includes:

[0174] Based on the static pressure distribution corresponding to the depth point, the static pressure inflection point is determined;

[0175] Based on the static pressure inflection point, the normalized height of the non-dominant phase fluid at the depth point is determined.

[0176] In one embodiment, calculating the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point includes:

[0177] Based on the normalized height of the non-dominant phase fluid at the depth point, the holdup of the non-dominant phase fluid at the depth point is calculated according to a preset fluid holdup calculation formula, which is:

[0178]

[0179] Where h is the normalized height of the non-dominant phase fluid at the depth point, and Y adv The holdup of the non-dominant phase fluid at the depth point is given by π, where π is the mathematical constant pi.

[0180] Based on the holdup of the non-dominant phase fluid at the depth point, the holdup of the dominant phase fluid at the depth point is calculated to obtain the holdup of each phase fluid at the depth point.

[0181] In one embodiment, the method further includes:

[0182] Obtain well logging curves, which are curves showing the change of static pressure with the position of the detection point;

[0183] Based on the well logging curves, the expression for water holdup is determined.

[0184] Based on the water holdup expression, the water holdup distribution of the wellbore cross section at the depth point is determined.

[0185] In one embodiment, the method further includes:

[0186] The total pressure, average pressure of each phase fluid, and wellbore temperature are obtained at each detection point in the cross-section of the wellbore where the depth point is located.

[0187] Based on the static pressure in the cross-section of the wellbore at the depth point and the total pressure at each detection point, the dynamic pressure at each detection point is calculated.

[0188] Based on the average pressure of each phase fluid and the wellbore temperature, the stratification density of each phase fluid in the wellbore environment is calculated;

[0189] Based on the dynamic pressure at each detection point and the stratification density of each phase fluid in the wellbore environment, the stratification velocity of each phase fluid at each detection point is obtained.

[0190] In one embodiment, it also includes:

[0191] Based on the location of each detection point and the corresponding stratification velocity of each phase fluid, the velocity profile of the fluid inside the wellbore is obtained.

[0192] In one embodiment, prior to obtaining multiple static pressures in the cross-section of the wellbore where the depth point is located, the method further includes:

[0193] Obtain the initial logging curve, which is the curve of the static pressure in the cross section of the wellbore at the depth point changing with the position of the detection point;

[0194] The initial logging curve is then repositioned to its depth to obtain the final logging curve.

[0195] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0196] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0197] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0198] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0199] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0200] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0201] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, or other data. Examples of computer storage media include, but are not limited to, phase-change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0202] It should also be noted that 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 process, method, article, or apparatus. Unless otherwise specified, 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 that element.

[0203] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for calculating the fluid holdup of each phase in a horizontal well, characterized in that, include: For any depth point on the wellbore, obtain multiple static pressures in the cross-section of the wellbore where the depth point is located; Based on multiple static pressures in the cross-section of the wellbore where the depth point is located, the static pressure distribution corresponding to the depth point is determined. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface. Based on the static pressure distribution corresponding to the depth point, the normalized height of the non-dominant phase fluid at the depth point is determined; Based on the normalized height of the non-dominant phase fluid at the depth point, the fluid holding capacity of each phase at the depth point is calculated.

2. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 1, characterized in that, There are multiple detection points in the cross-section of the wellbore where the depth point is located, and each detection point corresponds to a static pressure. The step of determining the static pressure distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore at the depth point includes: A two-dimensional coordinate system is established, wherein the origin of the two-dimensional coordinate system is the center of the cross-section of the well barrel where the depth point is located, the Y-axis of the two-dimensional coordinate system is perpendicular to the fluid streamline and points towards the ground, and the positive direction of the X-axis is the direction in which the Y-axis of the two-dimensional coordinate system is rotated 90° clockwise around the circumference of the cross-section of the well barrel where the depth point is located. Mark the position of each detection point in the two-dimensional coordinate system to obtain the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore. Based on the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore and the corresponding static pressure, the static pressure distribution corresponding to the depth point is determined.

3. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 2, characterized in that, The step of marking the positions of each detection point in the two-dimensional coordinate system and obtaining the normalized distance from the projection of each detection point onto the Y-axis to the center of the wellbore includes: Mark the position of each detection point in the two-dimensional coordinate system to obtain the initial coordinates of each detection point; The projection values ​​on the Y-axis of the initial coordinates of each detection point are normalized to obtain the normalized distance from the projection of each detection point on the Y-axis to the center of the wellbore.

4. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 1, characterized in that, The process of determining the normalized height of the non-dominant phase fluid at the depth point based on the hydrostatic pressure distribution corresponding to the depth point includes: Based on the static pressure distribution corresponding to the depth point, the static pressure inflection point is determined; Based on the static pressure inflection point, the normalized height of the non-dominant phase fluid at the depth point is determined.

5. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 1, characterized in that, The normalized height of the non-dominant phase fluid at the depth point is used to calculate the fluid holdup of each phase at the depth point, including: Based on the normalized height of the non-dominant phase fluid at the depth point, the holdup of the non-dominant phase fluid at the depth point is calculated according to a preset fluid holdup calculation formula, which is: Where h is the normalized height of the non-dominant phase fluid at the depth point, and Y adv The holdup of the non-dominant phase fluid at the depth point is given by π, where π is the mathematical constant pi. Based on the holdup of the non-dominant phase fluid at the depth point, the holdup of the dominant phase fluid at the depth point is calculated to obtain the holdup of each phase fluid at the depth point.

6. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 2, characterized in that, The method further includes: Obtain well logging curves, which are curves showing the change of static pressure with the position of the detection point; Based on the well logging curves, the expression for water holdup is determined. Based on the water holdup expression, the water holdup distribution of the wellbore cross section at the depth point is determined.

7. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 1, characterized in that, The method further includes: The total pressure, average pressure of each phase fluid, and wellbore temperature are obtained at each detection point in the cross-section of the wellbore where the depth point is located. Based on the static pressure in the cross-section of the wellbore at the depth point and the total pressure at each detection point, the dynamic pressure at each detection point is calculated. Based on the average pressure of each phase fluid and the wellbore temperature, the stratification density of each phase fluid in the wellbore environment is calculated; Based on the dynamic pressure at each detection point and the stratification density of each phase fluid in the wellbore environment, the stratification velocity of each phase fluid at each detection point is obtained.

8. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 7, characterized in that, Also includes: Based on the location of each detection point and the corresponding stratification velocity of each phase fluid, the velocity profile of the fluid inside the wellbore is obtained.

9. The method for calculating the fluid holdup of each phase in a horizontal well according to claim 1, characterized in that, Before obtaining multiple static pressures in the cross-section of the wellbore where the depth point is located, the method further includes: Obtain the initial logging curve, which is the curve of the static pressure in the cross section of the wellbore at the depth point changing with the position of the detection point; The initial logging curve is then repositioned to its depth to obtain the final logging curve.

10. A device for calculating the fluid holdup of each phase in a horizontal well, characterized in that, include: The acquisition module is used to acquire multiple static pressures in the cross-section of the wellbore at any depth point on the wellbore. A module is established to determine the static pressure distribution corresponding to the depth point based on multiple static pressures in the cross-section of the wellbore where the depth point is located. The static pressure distribution corresponding to the depth point is a static pressure projection distribution perpendicular to the fluid streamlines at the depth point and pointing towards the ground surface. The determination module is used to determine the normalized height of the non-dominant phase fluid at the depth point based on the static pressure distribution corresponding to the depth point; The calculation module is used to calculate the fluid holding capacity of each phase at the depth point based on the normalized height of the non-dominant phase fluid at the depth point.

11. An electronic device, characterized in that, The electronic device includes: At least one processor; A memory connected to the at least one processor; The memory stores instructions that can be executed by the at least one processor, and the at least one processor implements the method for calculating the fluid holdup of each phase in a horizontal well according to any one of claims 1 to 9 by executing the instructions stored in the memory.

12. A machine-readable storage medium storing instructions thereon, characterized in that, When executed by a processor, this instruction causes the processor to be configured to perform the method for calculating the fluid holdup of each phase in a horizontal well according to any one of claims 1 to 9.

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