Downhole holdup measurement methods, downhole fluid interface and geometric distribution determination methods

Abstract

The present application relates to a kind of downhole hold rate measurement method, downhole fluid interface and geometric distribution determination method, belong to oil and gas exploration technical field.The downhole hold rate measurement method utilizes multiple tuning forks distributed on flow cross section, realizes oil-water determination by comparing the size of fluid density collected by tuning fork with the size of preset oil-water density distinguishing threshold, realizes the representation of downhole fluid hold rate using the time proportion of oil / water collected by tuning fork, with the advantages of good universality, high measurement efficiency and high resolution.The downhole fluid interface determination method utilizes multiple tuning forks distributed on flow cross section to realize oil-water determination, identifies oil-water interface point according to oil-water alternative switching phenomenon, and determines horizontal well oil-water interface.The downhole fluid geometric distribution determination method utilizes multiple tuning forks distributed on flow cross section to realize oil-water determination, combines local oil hold rate calculation and tuning fork position distribution, and draws fluid geometric distribution diagram.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas exploration technology, and particularly relates to a method for measuring downhole holdup and a method for determining downhole fluid interfaces and geometric distributions. Background Technology

[0002] In oil and gas wells, the different types of light and heavy phases (oil, gas, water), their varying densities and flow rates, and the varying well conditions (vertical or horizontal) lead to highly complex downhole fluid flows. Due to the density differences among the fluid phases, fluid boundaries may occur in horizontal wells, while in vertical wells, the fluid phases exhibit different geometric distributions across the flow cross-section. Determining the holdup of each phase and the interface or geometric distribution of each phase across the flow cross-section under these complex downhole flow conditions remains a significant challenge.

[0003] Since the 1950s and 60s, downhole fluid holdup measurement both domestically and internationally has typically employed capacitive water holdup meters, radioactive water holdup meters, and downhole imaging logging techniques based on fluid conductivity-based flow imaging. No significant breakthroughs have been achieved in these technologies. Among these, capacitive water holdup meters are the most commonly used, and they are further divided into continuous capacitive water holdup meters and sampling capacitive water holdup meters. Each has its advantages and disadvantages: continuous capacitive water holdup meters can achieve continuous measurement, but when the water holdup exceeds 30%, the internal and external electrodes of the capacitor become conductive, resulting in a linear response regardless of water holdup changes, leading to a loss of resolution. Therefore, continuous capacitive water holdup meters are unsuitable for use in high water-cut oilfields due to their resolution limitations. Sampling capacitive water holdup meters measure after sampling and allowing the oil and water to separate, offering high resolution and enabling holdup measurement in high water-cut wells. However, their sampling and separation testing time is long (approximately 30 minutes per measurement point), resulting in low measurement efficiency. Radioactive water holdup meters require a radioactive source, leading to high costs. Flow imaging instruments determine whether something is oil or water by detecting the difference in conductivity when their probes encounter oil and water. However, their probes are easily encased in oil films, which isolates them from the test environment and causes water to be mistakenly identified as oil, greatly reducing resolution.

[0004] Furthermore, while laboratory horizontal pipe simulations can clearly observe the flow patterns and interface between the oil and water phases in horizontal wells, there is currently no direct and effective testing method for determining the oil-water flow interface downhole. Similarly, identifying the fluid flow geometry and determining the flow pattern in vertical wells faces the same challenges.

[0005] Therefore, how to provide a downhole fluid holdup measurement method that is universal, efficient, and low-cost, how to determine the fluid flow interface in horizontal wells, and how to determine the geometric distribution of each phase fluid in vertical wells are all technical problems that urgently need to be solved. Summary of the Invention

[0006] To address the aforementioned technical problems, this invention provides a downhole holdup measurement method and a method for determining downhole fluid interfaces and geometric distributions. The downhole holdup measurement method uses multiple tuning forks distributed across the flow cross-section to measure downhole fluid holdup, offering advantages such as good versatility, high measurement efficiency, and high resolution. The downhole fluid interface determination method overcomes the technical challenge of determining the oil-water interface in horizontal wells, providing a direct and effective method for determining fluid interfaces in horizontal wells. The downhole fluid geometric distribution determination method overcomes the technical challenge of visually displaying the geometric distribution of fluids in vertical wells, providing a direct and effective method for displaying the geometric distribution of fluids in vertical wells, which is beneficial for determining the flow pattern within vertical wells.

[0007] The first aspect of the present invention provides a downhole fluid holdup measurement method, which uses a distributed tuning fork downhole fluid holdup measuring instrument for measurement. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least 8 tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing through a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are extended, the multiple tuning forks are arranged in a multi-ring distribution relative to the axis of the housing.

[0008] The measurement method includes the following steps:

[0009] S11. Place the distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state downhole along the wellbore, and extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section to be measured downhole;

[0010] S12. Utilize the distributed tuning fork downhole fluid holdup measuring instrument to continuously collect the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, determine that the fluid currently flowing through the location of the tuning fork is water; otherwise, determine that it is oil.

[0011] S13. Calculate the local water holding rate and local oil holding rate of each tuning fork location according to formulas (1-1) and (1-2), and calculate the total water holding rate and total oil holding rate corresponding to the flow section to be measured according to formulas (1-3) and (1-4).

[0012] Formula (1-1)

[0013] Formula (1-2)

[0014] Formula (1-3)

[0015] Formula (1-4)

[0016] in, i =1, 2, 3... n ; n The number of tuning forks is dimensionless. Let be the local water holding capacity at the location of the i-th tuning fork, % . Let be the local oil retention rate at the location of the i-th tuning fork, %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is greater than the preset oil-water density distinction threshold; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is less than or equal to a preset oil-water density distinction threshold; The total water holding capacity of the measured flow section is %; denoted as the total oil holding capacity of the measured flow section.

[0017] In some embodiments, in step S12, the median value between the measured density of downhole crude oil and the measured density of formation water in the area to be measured is taken as a preset oil-water density distinction threshold.

[0018] In some embodiments, step S12 further includes converting the fluid density signal collected by the tuning fork into a binary pulse signal to record the judgment result. Specifically, the conversion steps are as follows: when the fluid density collected by the tuning fork is greater than a preset oil-water density distinction threshold, a signal of '1' is emitted and continues until the next collection; when the fluid density collected by the tuning fork is less than or equal to the preset oil-water density distinction threshold, a signal of '0' is emitted and continues until the next collection. In step S13, the sum of the durations of the pulse signals being '1' is taken as... The sum of the durations during which the pulse signal is 0 is taken as... .

[0019] The second aspect of the present invention provides a method for determining the fluid interface in a downhole well, which is applied to a horizontal well. The method uses a distributed tuning fork downhole fluid holdup measuring instrument to determine the fluid interface in the horizontal well. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least eight tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing through a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are extended, the multiple tuning forks are arranged in a multi-ring distribution relative to the axis of the housing.

[0020] The method for determining the downhole fluid interface includes the following steps:

[0021] S21. Place the distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state horizontally along the wellbore to the measurement position in the horizontal well, and extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section at the current measurement position.

[0022] S22. Using the distributed tuning fork downhole fluid holdup measuring instrument, each tuning fork continuously collects the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork is determined to be water; otherwise, it is determined to be oil. Within the preset collection time, when the fluid flowing through the location of a certain tuning fork continuously alternates between water and oil multiple times, the location of the tuning fork is identified as an oil-water boundary point of the flow section at the current measurement location. At least three oil-water boundary points are identified on the flow section at the current measurement location.

[0023] S23. Retract the telescopic arm and move the distributed tuning fork downhole fluid holdup measuring instrument horizontally to the next adjacent measurement position. Extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section at the current measurement position. Repeat step S22.

[0024] S24. Repeat step S23 to determine the oil-water interface on the flow section at several different measurement locations in the horizontal well. Connect the oil-water interface points and perform surface fitting to obtain the oil-water interface of the horizontal well.

[0025] In some embodiments, in step S22, the median value between the measured density of crude oil and the measured density of formation water in the horizontal well area to be tested is taken as the preset oil-water density distinction threshold.

[0026] In some embodiments, in step S22, the preset acquisition time is 2 to 8 seconds, and the number of alternation switching is at least 3 times.

[0027] In some embodiments, step S22 further includes: rotating the housing at the current measurement position to change the position of each tuning fork on the flow cross section, repeating the sampling until the oil-water boundary point is identified.

[0028] The third aspect of this invention provides a method for determining the geometric distribution of downhole fluids, applied to vertical wells. The method utilizes a distributed tuning fork downhole fluid holdup measuring instrument to determine the geometric distribution of fluids in a vertical well. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least eight tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing via a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are extended, the multiple tuning forks are arranged in multiple rings relative to the axis of the housing.

[0029] The method for determining the geometric distribution of downhole fluids includes the following steps:

[0030] S31. The distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state is vertically placed into the vertical well along the wellbore, and the telescopic arm is extended so that multiple tuning forks are located at different positions of the flow section to be measured in the vertical well.

[0031] S32. Using the distributed tuning fork downhole fluid holdup measuring instrument, each tuning fork continuously collects the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork is determined to be water; otherwise, it is determined to be oil.

[0032] S33. Calculate the local oil holding rate at the location of each tuning fork according to formula (2-1);

[0033] Formula (2-1)

[0034] in, i =1, 2, 3... n ; n The number of tuning forks is dimensionless. Let be the local oil retention rate at the location of the i-th tuning fork, %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is greater than the preset oil-water density distinction threshold; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is less than or equal to a preset oil-water density distinction threshold;

[0035] S34. Draw a circular area to represent the flow section to be measured in the vertical well. Determine the corresponding position of each tuning fork in the circular area based on the position of each tuning fork on the flow section to be measured. For all tuning forks with a local oil holding capacity that is not 0, draw circular oil bubbles at the corresponding positions of the tuning forks in the circular area to obtain the fluid geometry distribution diagram corresponding to the flow section. The area of ​​the circular oil bubbles at the corresponding positions of each tuning fork in the circular area is calculated according to formula (2-2).

[0036] Formula (2-2)

[0037] in, Let be the area of ​​the circular oil bubble at the position of the i-th tuning fork; Let be the area of ​​the circular region.

[0038] In some embodiments, in step S32, the median value between the measured density of downhole crude oil and the measured density of formation water in the vertical well area to be tested is taken as a preset oil-water density distinction threshold.

[0039] In some embodiments, step S32 further includes converting the fluid density signal collected by the tuning fork into a binary pulse signal to record the judgment result. Specifically, the conversion step is as follows: when the fluid density collected by the tuning fork is greater than a preset oil-water density distinction threshold, a signal of '1' is emitted and continues until the next collection; when the fluid density collected by the tuning fork is less than or equal to the preset oil-water density distinction threshold, a signal of '0' is emitted and continues until the next collection. The total number of collections is 3 to 5. In step S33, the sum of the durations of the pulse signals with a value of '1' is taken as... The sum of the durations during which the pulse signal is 0 is taken as... .

[0040] Compared with the prior art, the advantages and beneficial effects of the present invention are as follows:

[0041] 1. The downhole holdup measurement method provided by this invention is not only a new breakthrough in several downhole holdup measurement technologies that have been used domestically and internationally since the 1950s and 1960s, such as capacitance, radioactivity, and electrode probe, but also breaks through the limitation of conventional tuning forks being used only for measuring downhole fluid density. For the first time, the tuning fork is used for downhole fluid holdup measurement. Based on the fluid density collected by the tuning fork, oil and water are determined. Then, the proportion of time that oil / water flows through the tuning fork is collected to characterize the local oil holdup / local water holdup at the location of the tuning fork. Based on the local oil holdup and local water holdup, the total water holdup and total oil holdup corresponding to the flow section to be measured are calculated, thus realizing the characterization of downhole fluid holdup.

[0042] 2. The downhole fluid holdup measurement method provided by this invention is a novel downhole fluid holdup measurement method that differs from existing capacitive water holdup meters, radioactive water holdup meters, and downhole imaging logging technologies. It is not limited by high water cut conditions or oil film encapsulation, and can be adapted to various downhole conditions. It is applicable to both vertical and horizontal wells, has good versatility and high resolution. Moreover, its measurement steps are simple, it can be continuously measured without static placement, and has high measurement efficiency. At the same time, it does not require a radioactive source, and the measurement cost is low. It is significantly superior to existing downhole fluid holdup measurement methods and has important significance for guiding oilfield development and testing analysis.

[0043] 3. The downhole fluid holdup measurement method provided by this invention can measure downhole fluid density while simultaneously measuring downhole fluid holdup, effectively saving the workload of downhole fluid analysis and measurement;

[0044] 4. The downhole fluid interface determination method provided by this invention is based on the acquisition of fluid density by tuning fork to determine oil and water content. Then, it identifies the oil-water interface point of the horizontal well based on the phenomenon of oil-water alternation. By obtaining several oil-water interface points, the oil-water interface of the horizontal well is determined. This method overcomes the technical difficulty of determining the downhole oil-water interface of the horizontal well and provides a direct and effective method for determining the fluid interface of the horizontal well. It can provide data support for downhole flow imaging and is of great significance for guiding oilfield development.

[0045] 5. The method for determining the geometric distribution of downhole fluids provided by this invention is based on the fluid density collected by a tuning fork to determine oil and water content. Then, by combining the calculation of the local oil holding capacity at the location of the tuning fork and the positional distribution of the tuning fork on the flow section to be measured, a fluid geometric distribution map is drawn. This method overcomes the technical difficulty of intuitively displaying the geometric distribution of fluids in vertical wells, and provides a direct and effective method for displaying the geometric distribution of fluids in vertical wells. It is beneficial for determining the flow pattern in vertical wells and can provide data support for downhole flow imaging, which is of great significance for guiding oilfield development. Attached Figure Description

[0046] Figure 1 This is a front view of the distributed tuning fork downhole fluid holdup measuring instrument used in Embodiment 1 of the present invention in the retracted state of the telescopic boom;

[0047] Figure 2 This is a front view of the distributed tuning fork downhole fluid holdup measuring instrument used in Embodiment 1 of the present invention in the telescopic boom deployed state;

[0048] Figure 3 This is a side view of the distributed tuning fork downhole fluid holdup measuring instrument used in Embodiment 1 of the present invention in the telescopic boom deployment state;

[0049] Figure 4 This is a flowchart of the downhole holdup measurement method provided in Embodiment 1 of the present invention;

[0050] Figure 5 This is a schematic diagram of the distributed tuning fork downhole fluid holdup measuring instrument being lowered into the wellbore for data collection in the downhole holdup measurement method provided in Embodiment 1 of the present invention;

[0051] Figure 6 This is a flowchart of the downhole fluid interface determination method provided in Embodiment 2 of the present invention;

[0052] Figure 7 This is a schematic diagram of the distributed tuning fork downhole fluid holdup measuring instrument collecting data in a horizontal well in the downhole fluid interface determination method provided in Embodiment 2 of the present invention.

[0053] Figure 8 This is a flowchart of the method for determining the geometric distribution of downhole fluids provided in Embodiment 3 of the present invention;

[0054] Figure 9 This is a schematic diagram of the distributed tuning fork downhole fluid holdup measuring instrument collecting data in a vertical well in the downhole fluid geometry distribution determination method provided in Embodiment 3 of the present invention;

[0055] Figure 10 This is a schematic diagram of the fluid geometry distribution map drawn in the downhole fluid geometry distribution determination method provided in Embodiment 3 of the present invention.

[0056] In the picture:

[0057] 100. Distributed tuning fork downhole fluid holdup measuring instrument; 200. Wellbore; 300. Horizontal well; 400. Oil phase; 500. Water phase; 600. Vertical well; 700. Circular area; 800. Circular oil bubble;

[0058] 110. Shell; 111. First shell section; 112. Second shell section; 113. Telescopic rod;

[0059] 120. Telescopic arm; 121. First link; 122. Second link; 123. Tuning fork mount;

[0060] 130. Tuning fork; 131. Tuning fork on the outer ring; 132. Tuning fork on the inner ring;

[0061] 140. Alignment device. Detailed Implementation

[0062] The technical solutions in the embodiments of the present invention will be clearly and completely described below. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0063] Example 1

[0064] like Figures 1-5 As shown, this embodiment provides a downhole fluid holdup measurement method, which uses a distributed tuning fork downhole fluid holdup measuring instrument 100 for measurement.

[0065] like Figures 1-3As shown, the distributed tuning fork downhole fluid holdup measuring instrument 100 includes a housing 110 and multiple tuning forks 130 arranged at equal phase intervals along the circumference of the housing 110. Each tuning fork 130 is connected to the housing 110 via a corresponding telescopic arm 120. The telescopic arm 120 has a retracted state that rests against the outer wall of the housing 110 and an extended state that extends relative to the housing 110. When the telescopic arm 120 is in the retracted state, the tuning fork 130 rests against the outer wall of the housing 110 along with the telescopic arm 120. When the telescopic arm 120 is in the extended state, the tuning fork 130 is supported by the telescopic arm 120 and moved away from the outer wall of the housing 110. With this configuration, when the instrument is lowered, the retraction of the telescopic arm 120 facilitates the instrument's passage through the wellbore 200, preventing the tuning forks 130 from colliding with the wellbore 200 and causing damage. After reaching the downhole measurement position, the extension of the telescopic arm 120 allows the multiple tuning forks 130 to be positioned at different locations on the downhole flow section to be measured, facilitating the acquisition of data at different locations on the downhole flow section to be measured. It should be noted that arranging multiple tuning forks 130 at equal phase intervals ensures that the tuning forks are evenly distributed across the flow cross section being measured. It should also be noted that, to improve the accuracy of the measurement results, the number of tuning forks 130 should be at least eight; the more tuning forks 130 there are, the more accurate the measurement results will be.

[0066] To achieve the retraction and extension of the telescopic boom 120, specifically, as follows: Figures 1-3 As shown, in this embodiment, the housing 110 includes a first housing segment 111 and a second housing segment 112 arranged coaxially. The first housing segment 111 is connected to the second housing segment 112 via a telescopic rod 113 to reciprocate relative to the second housing segment 112. The axial end of the first housing segment 111 away from the second housing segment 112 is an insertion end for extending into the well. The telescopic arm 120 includes a tuning fork mounting base 123 for mounting the tuning fork 130 and a first connecting rod 121 and a second connecting rod 122 respectively hinged to both sides of the tuning fork mounting base 123. The first connecting rod 121 and the second connecting rod 122 have the same length. The first connecting rod 121... One end of the second connecting rod 122, away from the tuning fork mounting base 123, is hinged to the outer wall of the first housing segment 111, and the other end of the second connecting rod 122, away from the tuning fork mounting base 123, is hinged to the outer wall of the second housing segment 112. The telescopic rod 113 extends to drive the first housing segment 111 away from the second housing segment 112, and the first housing segment 111 drives the first connecting rod 121 and the second connecting rod 122 to rotate inward, thus retracting the telescopic arm 120. The telescopic rod 113 retracts to drive the first housing segment 111 closer to the second housing segment 112, and the first housing segment 111 drives the first connecting rod 121 and the second connecting rod 122 to rotate outward, thus extending the telescopic arm 120.

[0067] It should be noted that, as Figures 1-3As shown, after the telescopic arm 120 is extended, the multiple tuning forks 130 are arranged in multiple rings relative to the axis of the housing 110. The length of the telescopic arm 120 connected to the tuning forks 130 in the same ring (i.e., the total length of the first connecting rod 121 and the second connecting rod 122) is the same. The length of the telescopic arm 120 of the outer ring tuning fork 131 is longer than the length of the telescopic arm 120 of the inner ring tuning fork 132. Thus, when the telescopic rod 113 retracts to drive the first housing section 111 to approach the second housing section 112, the tuning forks 130 can be arranged in multiple rings around the outer periphery of the housing 110.

[0068] It should also be noted that, such as Figure 1 and Figure 2 As shown, in order to control the angle of the distributed tuning fork downhole fluid holdup measuring instrument 100, a centralizer 140 is also provided on the outer periphery of the housing 110.

[0069] In addition, those skilled in the art can also use other structures of distributed tuning fork downhole fluid holdup measuring instruments 100, as long as they can achieve "installing tuning fork 130 through telescopic arm 120 and adjusting the position of tuning fork 130 by contraction or expansion of telescopic arm 120". For example, based on the horizontal well water holdup measuring device disclosed in the existing Chinese utility model patent CN210714671U, tuning fork 130 can be used instead of water holdup meter, wherein the tuning fork 130 can be an existing miniature tuning fork.

[0070] like Figure 4 and Figure 5 As shown, the downhole holdup measurement method provided in this embodiment includes the following steps:

[0071] S11. Place the distributed tuning fork downhole fluid holdup measuring instrument 100 with the telescopic arm 120 in the retracted state downhole along the wellbore 200, and extend the telescopic arm 120 so that multiple tuning forks 130 are located at different positions of the flow section to be measured downhole.

[0072] In this step, it should be noted that after the telescopic arm 120 is extended, the multiple tuning forks 130 are arranged in multiple rings relative to the axis of the housing 110 on the flow section to be measured.

[0073] S12. Using the distributed tuning fork downhole fluid holdup measuring instrument 100, each tuning fork 130 continuously collects the fluid density flowing through the location of the tuning fork 130. When the fluid density collected by the tuning fork 130 is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork 130 is determined to be water; otherwise, it is determined to be oil.

[0074] In this step, it should be noted that the fluid density flowing through the tuning fork has the following relationship with the tuning fork vibration frequency (i.e., the principle formula for density measurement using existing tuning fork density meters):

[0075]

[0076] in, The density of the fluid flowing through the tuning fork; This is the natural frequency of the tuning fork; is the frequency generated when the fluid flows through the tuning fork; a, b, and c are constants that are related to the material, structure, and size of the tuning fork and can be obtained through experimental calibration.

[0077] The density of crude oil downhole (typically 0.8 g / cm³) 3 (Approximately) and the density of formation water (typically 1.0 g / cm³). 3 Since there is a difference between the left and right sides, this step is based on the difference in density between the oil and water phases. By setting a preset oil-water density distinction threshold, the fluid density flowing through the location of the tuning fork 130 is collected. By comparing the fluid density collected by the tuning fork 130 with the preset oil-water density distinction threshold, the fluid type is determined.

[0078] Preferably, the median value of the measured density of downhole crude oil and the measured density of formation water in the area to be logged is taken as the preset oil-water density distinction threshold, which helps to ensure the accuracy of fluid type determination.

[0079] In addition, to simplify the amount of data and facilitate the statistical time when calculating the fluid holdup, this step also includes converting the fluid density signal collected by the tuning fork 130 into a binary pulse signal to record the judgment result. The specific conversion steps are as follows: when the fluid density collected by the tuning fork 130 is greater than the preset oil-water density distinction threshold, a 1 signal is emitted and continues until the next collection; when the fluid density collected by the tuning fork 130 is less than or equal to the preset oil-water density distinction threshold, a 0 signal is emitted and continues until the next collection.

[0080] S13. Calculate the local water holding rate and local oil holding rate at the location of each tuning fork 130 according to formulas (1-1) and (1-2), and calculate the total water holding rate and total oil holding rate corresponding to the flow section to be measured according to formulas (1-3) and (1-4).

[0081] Formula (1-1)

[0082] Formula (1-2)

[0083] Formula (1-3)

[0084] Formula (1-4)

[0085] in, i =1, 2, 3... n ; nThe number of tuning forks is 130, dimensionless; Let be the local water holding capacity at the location of the i-th tuning fork 130, % . The local oil retention rate at the location of the i-th tuning fork 130 is %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork 130 is greater than the preset oil-water density distinction threshold; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork 130 is less than or equal to the preset oil-water density distinction threshold; The total water holding capacity of the measured flow section is %; denoted as the total oil holding capacity of the measured flow section.

[0086] Here, the sum of the durations of the pulse signal being 1 is taken as... The sum of the durations during which the pulse signal is 0 is taken as... .

[0087] In this step, the local water holding capacity at the location of the tuning fork 130 is characterized by the proportion of time that water flows through the tuning fork 130, and the local oil holding capacity at the location of the tuning fork 130 is characterized by the proportion of time that oil flows through the tuning fork 130. Then, the total water holding capacity and total oil holding capacity corresponding to the measured flow section are calculated based on the local water holding capacity and local oil holding capacity, thus realizing the measurement of downhole fluid holding capacity.

[0088] In this step, it should be noted that since multiple tuning forks 130 are set, and the sum of the total water holding rate and the total oil holding rate is 1, when calculating the total water holding rate and the total oil holding rate, the sum of the local water holding rate and the local oil holding rate of each tuning fork 130 is divided by the number of tuning forks 130.

[0089] In this step, it should be noted that, to ensure measurement accuracy and reduce measurement error, the average value of the data collected over 3 to 5 acquisition cycles is used for calculation. Preferably, the acquisition cycle is 1 minute.

[0090] The downhole holdup measurement method provided in this embodiment is not only a breakthrough in several downhole holdup measurement technologies that have been used domestically and internationally since the 1950s and 1960s, such as capacitance, radioactivity, and electrode probe, but also breaks through the limitation of conventional tuning forks being used only for measuring downhole fluid density. For the first time, the tuning fork 130 is used for downhole fluid holdup measurement. Based on the fluid density collected by the tuning fork 130, oil and water are determined. Then, the proportion of time that oil / water flows through the tuning fork 130 is used to characterize the local oil holdup / local water holdup at the location of the tuning fork 130. Based on the local oil holdup and local water holdup, the total water holdup and total oil holdup corresponding to the measured flow section are calculated, thus realizing the characterization of downhole fluid holdup. This method represents a novel approach to measuring downhole fluid holdup, distinct from existing capacitive water holdup meters, radioactive water holdup meters, and downhole imaging logging techniques. It is unaffected by high water cut conditions or oil film encapsulation, making it adaptable to various downhole conditions. It is applicable to both vertical and horizontal wells, offering good versatility and high resolution. Furthermore, its measurement steps are simple, allowing for continuous measurement without the need for static setup, resulting in high measurement efficiency. Simultaneously, it eliminates the need for a radioactive source, leading to low measurement costs. This significantly outperforms existing downhole fluid holdup measurement methods and is of great importance for guiding oilfield development and testing analysis. In addition, the downhole holdup measurement method provided in this embodiment can simultaneously measure downhole fluid density, effectively reducing the workload of downhole fluid analysis and measurement.

[0091] Example 2

[0092] This embodiment provides a method for determining the fluid interface in a downhole well 300. The method utilizes a distributed tuning fork downhole fluid holdup measuring instrument 100 to determine the fluid interface of the horizontal well 300. It should be noted that the structure of the distributed tuning fork downhole fluid holdup measuring instrument 100 used in this embodiment is the same as in Embodiment 1, and will not be described again here.

[0093] like Figure 6 and Figure 7 As shown, the downhole fluid interface determination method provided in this embodiment includes the following steps:

[0094] S21. The distributed tuning fork downhole fluid holdup measuring instrument 100 with the telescopic arm 120 in the retracted state is horizontally placed along the wellbore 200 into the measuring position inside the horizontal well 300, and the telescopic arm 120 is extended so that the multiple tuning forks 130 are located at different positions of the flow section at the current measuring position.

[0095] In this step, it should be noted that after the telescopic arm 120 is extended, the multiple tuning forks 130 are arranged in multiple rings on the flow section relative to the axis of the housing 110.

[0096] S22. Using the distributed tuning fork downhole fluid holdup measuring instrument 100, each tuning fork 130 continuously collects the fluid density flowing through the location of the tuning fork 130. When the fluid density collected by the tuning fork 130 is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork 130 is determined to be water; otherwise, it is determined to be oil. Within the preset collection time, when the fluid flowing through the location of a certain tuning fork 130 continuously alternates between water and oil multiple times, the location of the tuning fork 130 is identified as an oil-water boundary point of the flow section at the current measurement location. At least three oil-water boundary points are identified on the flow section at the current measurement location.

[0097] It should be noted that the principle of determining the fluid type based on the fluid density collected by the tuning fork 130 in this step is the same as in Example 1, and will not be repeated here. It should also be noted that in this step, when determining the fluid type based on the fluid density collected by the tuning fork 130, the median value of the measured crude oil density and the measured formation water density in the 300 area of ​​the horizontal well to be tested is taken as the preset oil-water density distinction threshold.

[0098] Within a horizontal well 300, the oil-water interface typically exhibits slight vertical fluctuations. Therefore, in this step, the oil-water interface point is identified by observing whether the fluid flowing through the tuning fork 130 continuously alternates between oil and water. Specifically, if the fluid flowing through the tuning fork 130 is consistently water within a preset sampling time, the location of the tuning fork 130 can be determined as the water phase 500; if the fluid flowing through the tuning fork 130 is consistently oil within the preset sampling time, the location of the tuning fork 130 can be determined as the oil phase 400; if the fluid flowing through the tuning fork 130 exhibits multiple consecutive oil-water alternations within the preset sampling time, it is likely due to vertical fluctuations at the oil-water interface, and the location of the tuning fork 130 can be determined as the oil-water interface point. To improve the accuracy of the oil-water interface point determination, preferably, the preset sampling time is 2-8 seconds, and the number of alternations is at least 3.

[0099] It should be noted that, as Figure 7 As shown, since multiple tuning forks 130 are located at different positions on the flow cross-section at the current measurement position, multiple different positions on the flow cross-section can be identified simultaneously. In this step, at least three oil-water boundary points are identified on the flow cross-section at each measurement position. By connecting the identified multiple oil-water boundary points, an oil-water boundary line can be drawn on the flow cross-section at the current measurement position. It can be understood that the more oil-water boundary points identified, the more accurate the obtained oil-water boundary line.

[0100] To increase the number of oil-water boundary points identified, especially to avoid the situation where the oil-water boundary points cannot be identified at a certain fixed placement angle of the distributed tuning fork downhole fluid holdup measuring instrument 100, preferably, this step also includes: rotating the housing 110 at the current measurement position to change the position of each tuning fork 130 on the flow section, and repeating the acquisition until multiple oil-water boundary points are identified.

[0101] It should be noted that, in order to avoid the disturbance of the fluid in the horizontal well 300 by the mobile distributed tuning fork downhole fluid holdup measuring instrument 100 affecting the crude oil-water interface, after the mobile distributed tuning fork downhole fluid holdup measuring instrument 100 or its housing 110 is rotated, it should be left to stand for a certain period of time (e.g., 3 s) before the oil-water interface is identified.

[0102] S23. Retract the telescopic arm 120 and move the distributed tuning fork downhole fluid holdup measuring instrument 100 in the horizontal direction to the next adjacent measurement position. Extend the telescopic arm 120 so that the multiple tuning forks 130 are located at different positions of the flow section at the current measurement position. Repeat step S22.

[0103] S24. Repeat step S23 to determine the oil-water interface at several different measurement locations within the horizontal well 300. Connect the oil-water interface points and perform surface fitting to obtain the oil-water interface of the horizontal well 300.

[0104] In this step, by repeatedly moving the distributed tuning fork downhole fluid holdup measuring instrument 100, the oil-water interface at several different measurement locations within the horizontal well 300 can be identified. That is, an oil-water interface line can be drawn for the flow section at each measurement location. Therefore, by connecting the oil-water interface points at several different measurement locations and then by surface fitting, the oil-water interface of the horizontal well 300 can be obtained.

[0105] The downhole fluid interface determination method provided in this embodiment uses the fluid density collected by the tuning fork 130 to determine oil-water content. Then, it identifies the oil-water interface point of the horizontal well 300 based on the oil-water alternation phenomenon. By obtaining several oil-water interface points, the oil-water interface of the horizontal well 300 is determined. This method overcomes the technical difficulty of determining the downhole oil-water interface in horizontal wells and provides a direct and effective method for determining the fluid interface in horizontal wells. It can provide data support for downhole flow imaging and is of great significance for guiding oilfield development.

[0106] Example 3

[0107] This embodiment provides a method for determining the geometric distribution of downhole fluids, applied to a vertical well 600. The method utilizes a distributed tuning fork downhole fluid holdup measuring instrument 100 to determine the fluid geometric distribution within the vertical well 600. It should be noted that the structure of the distributed tuning fork downhole fluid holdup measuring instrument 100 used in this embodiment is the same as in Embodiment 1, and will not be described again here.

[0108] like Figures 8-10 As shown, the method for determining the geometric distribution of downhole fluids provided in this embodiment includes the following steps:

[0109] S31. The distributed tuning fork downhole fluid holdup measuring instrument 100 with the telescopic arm 120 in the retracted state is vertically placed into the vertical well 600 along the wellbore 200, and the telescopic arm 120 is extended so that multiple tuning forks 130 are located at different positions of the flow section to be measured in the vertical well 600.

[0110] In this step, it should be noted that after the telescopic arm 120 is extended, the multiple tuning forks 130 are arranged in multiple rings on the flow section relative to the axis of the housing 110.

[0111] S32. Using the distributed tuning fork downhole fluid holdup measuring instrument 100, each tuning fork 130 continuously collects the fluid density flowing through the location of the tuning fork 130. When the fluid density collected by the tuning fork 130 is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork 130 is determined to be water; otherwise, it is determined to be oil.

[0112] It should be noted that the principle of determining the fluid type based on the fluid density collected by the tuning fork 130 in this step is the same as in Example 1, and will not be repeated here. It should also be noted that in this step, when determining the fluid type based on the fluid density collected by the tuning fork 130, the median value of the measured crude oil density and the measured formation water density in the 600-meter area of ​​the vertical well to be tested is taken as the preset oil-water density distinction threshold.

[0113] To simplify the data volume and facilitate the statistical analysis of time when calculating the local oil holding capacity, this step also includes converting the fluid density signal collected by the tuning fork 130 into a binary pulse signal to record the judgment result. Specifically, the conversion process is as follows: when the fluid density collected by the tuning fork 130 is greater than a preset oil-water density distinction threshold, a signal of '1' is emitted and continues until the next collection; when the fluid density collected by the tuning fork 130 is less than or equal to the preset oil-water density distinction threshold, a signal of '0' is emitted and continues until the next collection. The total number of collections is 3 to 5. It should be noted that since the fluid geometry distribution of the measured flow section changes over time, controlling the total number of collections to 3 to 5 is sufficient.

[0114] S33. The local oil retention rate at the location of each tuning fork 130 is calculated according to formula (2-1);

[0115] Formula (2-1)

[0116] in, i =1, 2, 3... n ; n The number of tuning forks is 130, dimensionless; The local oil retention rate at the location of the i-th tuning fork 130 is %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork 130 is greater than the preset oil-water density distinction threshold; The total cumulative time, in seconds, during which the fluid density collected by the i-th tuning fork 130 is less than or equal to the preset oil-water density distinction threshold.

[0117] Here, the sum of the durations of the pulse signal being 1 is taken as... The sum of the durations during which the pulse signal is 0 is taken as... .

[0118] It should be noted that the calculation principle of the local oil holding rate of each tuning fork 130 in this step is the same as that in Example 1, and will not be repeated here.

[0119] S34. Draw a circular area 700 to represent the flow section to be measured in the vertical well 600. Determine the corresponding position of each tuning fork 130 in the circular area 700 based on the position of each tuning fork 130 on the flow section to be measured. For all tuning forks 130 with a local oil holding capacity that is not 0, draw circular oil bubbles 800 at the corresponding positions of the tuning forks 130 in the circular area 700 to obtain the fluid geometry distribution diagram corresponding to the flow section. The area of ​​the circular oil bubbles 800 at the corresponding positions of each tuning fork 130 in the circular area 700 is calculated according to formula (2-2).

[0120] Formula (2-2)

[0121] in, Let be the area of ​​the circular oil bubble 800 at the position of the i-th tuning fork 130; Let 70 be the area of ​​the circular region.

[0122] In this step, it should be noted that when the local oil holding rate at the location of the tuning fork 130 is not zero, it indicates the presence of oil phase 400. Therefore, based on the position of the tuning fork 130 on the flow section to be measured, circular oil bubbles 800 can be drawn at the corresponding positions in the circular region 700 representing the flow section to be measured, representing oil phase 400. The area within the circular region 700 excluding the circular oil bubbles 800 represents water phase 500. The area ratio of the circular oil bubbles 800 within the circular region 700 is calculated based on the local oil holding rate; that is, the larger the local oil holding rate, the more oil phase is present, and thus the larger the oil bubble area. Thus, a fluid geometry distribution diagram of the flow section to be measured can be drawn.

[0123] The method for determining the downhole fluid geometry distribution provided in this embodiment uses the fluid density collected by the tuning fork 130 to determine oil and water content. Then, by combining the calculation of the local oil holding capacity at the location of the tuning fork 130 and the positional distribution of the tuning fork 130 in the flow section to be measured, a fluid geometry distribution map is drawn. This method overcomes the technical difficulty of intuitively displaying the fluid geometry distribution in a vertical well 600, and provides a direct and effective method for displaying the fluid geometry distribution in a vertical well 600. It is beneficial for determining the flow pattern within the vertical well 600, and can provide data support for downhole flow imaging, which is of great significance for guiding oilfield development.

Claims

1. A downhole holdup measurement method, characterized in that, The measurement was performed using a distributed tuning fork downhole fluid holdup measuring instrument. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least 8 tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing through a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are extended, the multiple tuning forks are arranged in multiple rings relative to the axis of the housing. The measurement method includes the following steps: S11. Place the distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state downhole along the wellbore, and extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section to be measured downhole; S12. Utilize the distributed tuning fork downhole fluid holdup measuring instrument to continuously collect the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, determine that the fluid currently flowing through the location of the tuning fork is water; otherwise, determine that it is oil. S13. Calculate the local water holding rate and local oil holding rate of each tuning fork location according to formulas (1-1) and (1-2), and calculate the total water holding rate and total oil holding rate corresponding to the flow section to be measured according to formulas (1-3) and (1-4). Official (1-1) Official (1-2) Official (1-3) Official (1-4) in, i =1, 2, 3... n ; n The number of tuning forks is dimensionless. Let be the local water holding capacity at the location of the i-th tuning fork, % . Let be the local oil retention rate at the location of the i-th tuning fork, %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is greater than the preset oil-water density distinction threshold; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is less than or equal to a preset oil-water density distinction threshold; The total water holding capacity of the measured flow section is %; denoted as the total oil holding capacity of the measured flow section.

2. The downhole holdup measurement method according to claim 1, characterized in that, In step S12, the median value of the measured density of downhole crude oil and the measured density of formation water in the area to be measured is taken as the preset oil-water density distinction threshold.

3. The downhole holdup measurement method according to claim 1, characterized in that, Step S12 further includes converting the fluid density signal collected by the tuning fork into a binary pulse signal to record the judgment result. Specifically, the conversion steps are as follows: when the fluid density collected by the tuning fork is greater than a preset oil-water density distinction threshold, a signal of '1' is emitted and continues until the next collection; when the fluid density collected by the tuning fork is less than or equal to the preset oil-water density distinction threshold, a signal of '0' is emitted and continues until the next collection. In step S13, the sum of the durations of the pulse signals that are '1' is taken as... The sum of the durations during which the pulse signal is 0 is taken as... .

4. A method for determining the fluid interface in downhole wells, applied to horizontal wells, characterized in that: The fluid interface of a horizontal well is determined using a distributed tuning fork downhole fluid holdup measuring instrument. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least 8 tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing through a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are extended, the multiple tuning forks are arranged in multiple rings relative to the axis of the housing. The method for determining the downhole fluid interface includes the following steps: S21. Place the distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state horizontally along the wellbore to the measurement position in the horizontal well, and extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section at the current measurement position. S22. Using the distributed tuning fork downhole fluid holdup measuring instrument, each tuning fork continuously collects the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork is determined to be water; otherwise, it is determined to be oil. Within the preset collection time, when the fluid flowing through the location of a certain tuning fork continuously alternates between water and oil multiple times, the location of the tuning fork is identified as an oil-water boundary point of the flow section at the current measurement location. At least three oil-water boundary points are identified on the flow section at the current measurement location. S23. Retract the telescopic arm and move the distributed tuning fork downhole fluid holdup measuring instrument horizontally to the next adjacent measurement position. Extend the telescopic arm so that multiple tuning forks are located at different positions of the flow section at the current measurement position. Repeat step S22. S24. Repeat step S23 to determine the oil-water interface on the flow section at several different measurement locations in the horizontal well. Connect the oil-water interface points and perform surface fitting to obtain the oil-water interface of the horizontal well.

5. The method for determining the downhole fluid interface according to claim 4, characterized in that, In step S22, the median value of the measured density of crude oil and the measured density of formation water in the horizontal well area to be tested is taken as the preset oil-water density distinction threshold.

6. The method for determining the downhole fluid interface according to claim 4, characterized in that, In step S22, the preset acquisition time is 2~8 s, and the number of alternation switching is at least 3 times.

7. The method for determining the downhole fluid interface according to claim 4, characterized in that, Step S22 further includes: rotating the housing at the current measurement position to change the position of each tuning fork on the flow section, repeating the sampling until the oil-water boundary point is identified.

8. A method for determining the geometric distribution of downhole fluids, applied to vertical wells, characterized in that: The geometric distribution of fluid in a vertical well is determined using a distributed tuning fork downhole fluid holdup measuring instrument. The distributed tuning fork downhole fluid holdup measuring instrument includes a housing and at least 8 tuning forks arranged at equal phase intervals along the circumference of the housing. Each tuning fork is connected to the housing through a corresponding telescopic arm. The telescopic arms corresponding to the tuning forks have different lengths so that after the telescopic arms are deployed, the multiple tuning forks are arranged in multiple rings relative to the axis of the housing. The method for determining the geometric distribution of downhole fluids includes the following steps: S31. The distributed tuning fork downhole fluid holdup measuring instrument with the telescopic arm in the retracted state is vertically placed into the vertical well along the wellbore, and the telescopic arm is extended so that multiple tuning forks are located at different positions of the flow section to be measured in the vertical well. S32. Using the distributed tuning fork downhole fluid holdup measuring instrument, each tuning fork continuously collects the fluid density flowing through the location of the tuning fork. When the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, the fluid currently flowing through the location of the tuning fork is determined to be water; otherwise, it is determined to be oil. S33. Calculate the local oil holding rate at the location of each tuning fork according to formula (2-1); Official (2-1) in, i =1, 2, 3... n ; n The number of tuning forks is dimensionless. Let be the local oil retention rate at the location of the i-th tuning fork, %; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is greater than the preset oil-water density distinction threshold; The total cumulative time (in seconds) during which the fluid density of the i-th tuning fork is less than or equal to a preset oil-water density distinction threshold; S34. Draw a circular area to represent the flow section to be measured in the vertical well. Determine the corresponding position of each tuning fork in the circular area based on the position of each tuning fork on the flow section to be measured. For all tuning forks with a local oil holding capacity that is not 0, draw circular oil bubbles at the corresponding positions of the tuning forks in the circular area to obtain the fluid geometry distribution diagram corresponding to the flow section. The area of ​​the circular oil bubbles at the corresponding positions of each tuning fork in the circular area is calculated according to formula (2-2). Official (2-2) in, Let be the area of ​​the circular oil bubble at the position of the i-th tuning fork; Let be the area of ​​the circular region.

9. The method for determining the geometric distribution of downhole fluids according to claim 8, characterized in that, In step S32, the median value of the measured density of downhole crude oil and the measured density of formation water in the vertical well area to be tested is taken as the preset oil-water density distinction threshold.

10. The method for determining the geometric distribution of downhole fluids according to claim 8, characterized in that, Step S32 further includes converting the fluid density signal collected by the tuning fork into a binary pulse signal to record the judgment result. The specific conversion steps are as follows: when the fluid density collected by the tuning fork is greater than the preset oil-water density distinction threshold, a signal of 1 is emitted and continues until the next collection; when the fluid density collected by the tuning fork is less than or equal to the preset oil-water density distinction threshold, a signal of 0 is emitted and continues until the next collection. The total number of collections is 3 to 5. In step S33, the sum of the durations of the pulse signal being 1 is taken as the result. The sum of the durations during which the pulse signal is 0 is taken as... .

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