Horizontal well production profile imaging logging instrument

Abstract

The invention relates to the field of horizontal well logging of high petroleum and natural gas engineering, in particular to a horizontal well output profile imaging logging instrument. The horizontal well output profile imaging logging instrument comprises a shell and supporting structures in groups, the supporting structures are evenly arranged on the shell in the circumferential direction, a detection assembly is arranged on each supporting structure, and each detection assembly comprises a capacitance sensor and / or an electrode sensor. The same sensors on all the supporting structures are arranged in the casing pipe in an annular array coaxial with the casing pipe to form a circular imaging face, equal-diameter imaging is conducted on the circular imaging face, the logging instrument further comprises a data processing module connected with the sensors and a power module used for supplying power, and the testing accuracy is improved.

Description

Technical Field

[0001] This invention relates to the field of horizontal well logging in oil and gas engineering, and specifically to a horizontal well production profile imaging logging tool. Background Technology

[0002] In the mid-to-late stages of oil and gas reservoir development, horizontal well development is often adopted to effectively increase oil and gas production, following the principle of "fewer wells, higher production." Compared to vertical wells, horizontal wells increase the exposed area of ​​the oil and gas layer, resulting in longer production intervals and higher yields. Production profiles are the most direct means of understanding the downhole production status of oil and gas wells. During production, parameters such as temperature, flow pattern, flow rate, and phase fraction are generally measured as monitoring parameters for the three-phase flow of oil, gas, and water in horizontal well production profile logging. This allows for timely understanding and control of the oil and gas content in the underground reservoir, assessment of the production status of each interval, and guidance for subsequent reservoir stimulation design optimization and production dynamic management.

[0003] Due to the density differences between oil, gas, and water, the fluid flow in the horizontal section of a horizontal well differs from that in a vertical well. Under gravity separation, the flow is dominated by laminar flows of gas, oil, and water from top to bottom. As the gas flow rate increases, the mixed flow patterns, such as phase-separated flow, intermittent flow, and uniformly distributed flow, become complex and varied. Conventional testing instruments adapted to single-phase flow in vertical pipes cannot be directly applied to the measurement of multiphase flow in the downhole horizontal section.

[0004] Currently, horizontal well production profile logging, both domestically and internationally, typically utilizes coiled tubing or a crawler to deliver multi-probe array instruments to measure parameters such as flow rate, holdup, well temperature, and pressure in each section, thereby understanding the production status of each section of the horizontal well. The FSI fluid scanning imager is the most mainstream horizontal well production profile logging system internationally. It longitudinally mounts four turbine flow meters, six optical gas holdup detectors, and six water holdup detectors on a push-type measuring arm, vertically covering the well axis to acquire measurements at corresponding locations. During measurement, the turbine flow meters may become stuck or suffer blade damage when encountering sludge, debris, etc., compromising the instrument's structure and hindering successful monitoring. GE's Sondex MAPS instrument can measure the holdup and velocity of the three phases (oil, gas, and water) in horizontal wells. The turbine flow meters are arranged on lantern-type centralizers, primarily measuring near-wellbore velocities. However, the flow meters have a high starting displacement, the array probes are prone to damage, and the logging success rate is low.

[0005] Chinese patent document CN202850974U discloses a three-phase production profile logging tool for low-yield liquid wells, comprising a collector, an oil-water interface measuring device, a gas phase control device, and an impedance water cut meter. The gas phase flows in through the gas phase control valve inlet and out through the gas phase outlet; the oil-water phase flows in through the oil-water phase inlet and out after passing through the impedance water cut meter. The umbrella-type collector serves as a measuring container, measuring the volumetric flow rate of the gas and oil phases after gravity separation. The oil-water interface measuring device detects the oil-water interface after gravity separation, the gas phase control device accumulates and releases the gas phase, and the impedance water cut meter measures the water cut of the oil and water phases. This instrument employs a flow collection measurement method, using array sensor technology and volumetric measurement to measure the volumetric flow rate of the gas and oil phases after gravity separation, targeting the production of each layer. It can directly measure the oil flow rate in low-production wells. However, this logging tool cannot measure the total amount of fluid in the entire wellbore. Furthermore, the use of an umbrella-type flow collector to collect the phases before measurement causes changes in the fluid state as the phases pass through each detection electrode, resulting in inconsistencies between the parameters measured by each detection electrode and the actual fluid parameters in low-production wells. Additionally, this logging tool cannot be used in horizontal wells.

[0006] Chinese patent document CN108397183B discloses a low-production horizontal well production profile logging combination instrument with dual working modes. It consists of a collector short-circuit and a dual-working-mode logging combination sensor short-circuit, mainly including a collector, a shell, a rotatable cavity, and a rotatable cavity inlet. The measuring mechanism includes a total water value measurement sensor, a conductivity-type water cut meter, a turbine flow meter, and a single-phase flow measurement sensor, used to measure the conductivity of the aqueous phase, the conductivity of the oil-water miscible phase, the total volumetric flow rate of the fluid, and the single-phase flow rate under low production conditions, respectively. The water cut is measured using the conductivity method. The total water value measurement sensor consists of 12 probe electrodes fixed to the inner wall of an insulator support. Specifically, 6 excitation electrodes and 6 measuring electrodes are evenly distributed circumferentially at intervals on the same cross-section along the upstream and downstream axial directions of the inner wall of the insulator support, arranged in parallel and corresponding positions. The flow measurement sensor consists of 7 conductivity probes evenly distributed along the diameter of their circular end faces. During testing, measurements were taken in different sections. The fluid entered the combined instrument through the collector and the conductivity of the aqueous phase was measured by 12 circumferentially distributed six-pair conductivity probes. The conductivity of the oil-water mixed phase was measured by a conductivity water content meter, and the ratio of the two was used to calculate the holdup. The fluid flow rate was measured by a turbine flow meter. The oil-water liquid level height was measured by a multi-probe single-phase flow measurement sensor, and the single-phase flow rate under the condition of oil-water stratified flow was calculated.

[0007] The instrument has a complex structure. During testing, the oil-water mixed-phase fluid is collected by a collector into a collection channel, and then the fluid in the collection channel is introduced into the rotatable cavity through the inlet. As the fluid flows through the sensors, relevant parameters are measured. Because this logging assemblies also require the fluid to be collected into the rotatable cavity before parameter measurement, and because the fluid undergoes two collection processes before the parameters are measured, the fluid state changes as it passes through the sensors. This results in a certain error between the parameters measured by the sensors and the actual fluid parameters in the horizontal well, failing to reflect the true fluid information. Furthermore, this logging assemblies can only collect oil and water two-phase fluids into the rotatable cavity for measurement. It is only suitable for testing the production of oil-water two-phase fluids in horizontal wells with a water cut of less than 40%, and cannot measure the fluid flow regime, holdup, and flow rate of the three-phase oil, gas, and water. Summary of the Invention

[0008] The purpose of this invention is to provide a horizontal well production profile imaging logging tool to solve the problem in the prior art where the logging combination tool undergoes flow collection before obtaining parameters, causing changes in the fluid state as the fluid passes through each sensor, resulting in inaccurate parameters.

[0009] To solve the above problems, the technical solution of the horizontal well production profile imaging logging tool of the present invention is as follows:

[0010] A horizontal well production profile imaging logging tool includes a housing and a group of support structures. The support structures are uniformly arranged circumferentially on the housing. Detection components are provided on the support structures. Each detection component includes a capacitive sensor and / or an electrode sensor. Identical sensors on each support structure are arranged in a ring array coaxial with the casing to form a circular imaging surface inside the casing. The circular imaging surface is of equal diameter. The logging tool also includes a data processing module connected to the sensors and a power supply module for powering them.

[0011] Furthermore, the support structure includes a contact rod extending axially along the housing, the contact rod being used to contact the inner wall of the sleeve and being axially movable relative to the inner wall of the sleeve, and the detection component being disposed on the contact rod.

[0012] Furthermore, the number of detection components is 2-6. When the number of detection components is 3 or more, the detection components on the contact rod are arranged at equal intervals along the axial direction of the housing.

[0013] Furthermore, the detection component includes a capacitive sensor and an electrode sensor.

[0014] Furthermore, the capacitive sensor and the electrode sensor are spaced apart, and the spacing between the capacitive sensor and the electrode sensor is equal to the spacing between the detection components.

[0015] Furthermore, the number of the support structures is 4-24 and is an even number.

[0016] Furthermore, the support structure is an elastic floating structure that floats radially along the shell.

[0017] Furthermore, the support structure includes a support rod disposed opposite to the contact rod, the two ends of the support rod being hinged to the contact rod and forming an obtuse angle with the contact rod, and also includes a sliding structure disposed opposite to the support rod and hinged to the end of the support rod away from the contact rod, and an elastic structure for providing the sliding structure with the ability to move closer to each other along the axial direction of the housing.

[0018] Furthermore, the sliding structure is a sliding sleeve, and the end of each support rod away from the contact rod is hinged to the corresponding sliding sleeve.

[0019] Furthermore, the elastic structure is a compression spring, and the housing has opposing limiting shoulders, with the compression spring installed between the sliding sleeve and the limiting shoulders.

[0020] Furthermore, the support structure is a support arm mounted on the housing, the outer end of the support arm has a contact end for contacting the inner wall of the sleeve, and the sensor is disposed on the support arm radially close to the contact end.

[0021] Furthermore, the support arm is hinged to the housing, and the housing is provided with a retaining mechanism that keeps the support arm in an outward extended state and an inward retracted state.

[0022] Furthermore, the holding mechanism includes a transmission rod arranged along the length of the housing, and a drive device for controlling the reciprocating motion of the transmission rod along the axial direction of the housing. The transmission rod is hinged to the support arm and drives the support arm to swing to the extended state and the retracted state when the transmission rod is driven to move linearly by the drive device.

[0023] Furthermore, the driving device includes an electromagnet and a ferromagnetic component, one of which is fixedly installed inside the housing, and the other is fixedly installed at the end of the transmission rod. A compression spring is installed between the electromagnet and the ferromagnetic component.

[0024] Furthermore, each support arm is provided with a corresponding retaining mechanism.

[0025] Furthermore, the logging tool also includes sensors for calculating the opening angle of each support arm, wherein the sensors are displacement sensors mounted on the transmission rod.

[0026] Beneficial effects: The horizontal well production profile imaging logging tool of the present invention uses a set of support structures evenly distributed on the circumference of the casing. The support structures are equipped with detection components, including a capacitive sensor and / or an electrode sensor. The same sensors on each support structure are arranged in a ring array coaxial with the casing to form a circular imaging surface inside the casing, and the circular imaging surface is of equal diameter.

[0027] This logging tool does not require flow collection for measurement. Each phase directly passes through capacitive and / or electrode sensors to obtain its corresponding dielectric constant and / or conductivity. The phase state does not change due to flow collection when passing through these sensors. A circular imaging surface obtains the true fluid cross-section information within the sleeve, ensuring that the parameters measured by each capacitive and / or electrode sensor are consistent with the parameters of each phase in the actual horizontal well. This provides more comprehensive fluid response values, enabling accurate judgment of fluid flow regime changes and thus higher accuracy in calculating the holdup and flow rate of each phase. Furthermore, the logging tool directly tests the phases present in the horizontal well, making it suitable for testing the fluid regime, holdup, and flow rate of any two phases in oil, water, and gas in horizontal wells, as well as for testing the fluid regime, holdup, and flow rate of all three phases. Compared to turbine flow meters, the capacitive and electrode sensors have simpler structural design and testing processes, reducing the probability of instrument failure downhole and improving logging success rate. Attached Figure Description

[0028] Figure 1 This is a schematic diagram of the logging instrument structure in Embodiment 1 of the horizontal well production profile imaging logging instrument of the present invention;

[0029] Figure 2 This is a schematic diagram of the tomographic imaging mode in Embodiment 5 of the horizontal well production profile imaging logging tool of the present invention;

[0030] Figure 3 This is a schematic diagram of the sensor distribution in Embodiment 5 of the horizontal well production profile imaging logging tool of the present invention;

[0031] Figure 4 This is a schematic diagram of the working modes of each sensor in Embodiment 5 of the horizontal well production profile imaging logging tool of the present invention;

[0032] Figure 5 This is a flowchart of flow imaging and water holdup measurement in Embodiment 5 of the horizontal well production profile imaging logging tool of the present invention;

[0033] Figure 6 This is a flow chart of flow measurement in Embodiment 5 of the horizontal well production profile imaging logging tool of the present invention;

[0034] Figure 7This is a schematic diagram of the unfolded structure of Embodiment 6 of the horizontal well production profile imaging logging tool of the present invention;

[0035] Figure 8 This is a schematic diagram of the recovery structure in Embodiment 8 of the horizontal well production profile imaging logging tool of the present invention;

[0036] Figure 9 This is a schematic diagram of the water holdup measurement mode in Embodiment 9 of the horizontal well production profile imaging logging tool of the present invention;

[0037] Figure 10 This is a schematic diagram of the calculation of the support arm forming radius in Embodiment 9 of the horizontal well production profile imaging logging tool of the present invention;

[0038] Figure 11 This is a schematic diagram of the flow measurement mode in Embodiment 10 of the horizontal well production profile imaging logging tool of the present invention;

[0039] In the diagram: 1. Housing, 2. Threaded joint, 3. Support rod, 4. Contact rod, 5. Capacitive sensor, 6. Electrode sensor, 7. Upper compression spring, 8. Upper sliding sleeve, 9. Lower sliding sleeve, 10. Lower compression spring, 11. DSP processor, 12. Battery, 13. Storage unit, 14. Guide cone, 15. Support arm, 16. Transmission rod, 17. Electromagnet, 18. Iron plate, 19. Compression spring, 20. Hollow sleeve, 21. Roller, 22. Displacement sensor, 23. Insulating gasket. Detailed Implementation

[0040] The features and performance of the present invention will be described in further detail below.

[0041] As cited in the background art, in existing logging instruments, fluid is collected into a rotatable cavity before relevant parameter measurements can be performed. Furthermore, the fluid undergoes two collection processes before the parameters are measured, causing changes in the fluid state as it passes through each sensor. This results in errors between the parameters measured by each sensor and the actual fluid parameters in the horizontal well. Therefore, this invention provides a horizontal well production profile imaging logging instrument, including a housing and a group of support structures. Detection components are mounted on the support structures. The sensors include a capacitive sensor and / or an electrode sensor. Identical sensors on each support structure are arranged in a circular array coaxial with the casing, forming a circular imaging surface within the casing. The circular imaging surface is of equal diameter and serves as a detection surface for information acquisition. A data processing module is used to acquire and transmit relevant data, and a power supply module supplies power to the sensors and the data processing module. The relevant data for the capacitive sensor includes its measured dielectric constant, the response time of the dielectric constant, and the depth of the capacitive sensor. The relevant data for the electrode sensor includes its measured conductivity, the response time of the conductivity, and the depth of the electrode sensor. Based on the above data and through calculation, the sustaining capacity and fluid flow state of the multiphase flow in the test horizontal section can be obtained, and the fluid flow rate can be calculated.

[0042] The horizontal well production profile imaging logging tool of this invention does not require flow collection for measurement. This logging tool obtains the true fluid cross-sectional information within the casing through a circular imaging surface formed by capacitive sensors and / or electrode sensors. This ensures that the parameters measured by each sensor are consistent with the parameters of each phase in the actual horizontal well, while simultaneously acquiring more comprehensive fluid response values. This allows for accurate judgment of changes in fluid flow regime, resulting in higher accuracy in calculating the holdup and flow rate of each phase. Furthermore, capacitive sensors are suitable for low water cut conditions, while electrode sensors are suitable for high water cut conditions; their combination makes the test more accurate. This method directly tests based on the phases present in the horizontal well, applicable to the fluid flow regime, holdup, and flow rate testing of any two phases in the oil, water, and gas components of a horizontal well, as well as the fluid flow regime, holdup, and flow rate testing of all three phases. Additionally, the capacitive and electrode sensors have simple structures, higher anti-fouling and anti-sticking capabilities, and are less prone to damage, reducing the probability of instrument failure downhole and improving the logging success rate.

[0043] Example 1 of the horizontal well production profile imaging logging tool of the present invention:

[0044] In this embodiment, as Figure 1 , Figure 2 , Figure 3As shown, the horizontal well production profile imaging logging tool includes a housing 1, which is cylindrical. The top of the housing 1 has a connector for connecting to coiled tubing, and the tubing and logging tool are connected via threads 2. It also includes 12 support structures, evenly arranged circumferentially on the housing 1. Two detection components are arranged along the axial direction of the housing 1 on each support structure. Each detection component includes a capacitance sensor 5 and an electrode sensor 6, spaced apart. The capacitance sensors 5 and electrode sensors 6 on each support structure are arranged in a ring array coaxially with the casing, forming four circular imaging surfaces within the casing, and the four circular imaging surfaces are of equal diameter. The horizontal well production profile imaging logging tool also includes a data processing module and a power module, both installed inside the housing 1. The data processing module is connected to the capacitance sensors 5 and electrode sensors 6 for processing the acquired data. The power module supplies power to the capacitance sensors 5, electrode sensors 6, and the data processing module. In this embodiment, the capacitance sensor 5 is suitable for low water cut conditions, and the electrode sensor 6 is suitable for high water cut conditions; their combination makes the testing more accurate.

[0045] Capacitive sensor 5 and electrode sensor 6 can be positioned on the support structure near the housing 1. However, the circular imaging surface formed by these sensors has a small diameter within the casing, resulting in limited fluid-related information across the entire wellbore cross-section and inaccurate results. Therefore, in this embodiment, the support structure preferably includes a contact rod 4 extending axially along the housing for contact with the inner wall of the casing. Both capacitive sensor 5 and electrode sensor 6 are positioned on the contact rod 4 facing the housing 1. Simultaneously, the sensors on the contact rod 4 are evenly spaced along the housing axial direction, ensuring that the circumferential imaging surfaces of the capacitive sensor 5 and electrode sensor 6 are evenly distributed along the housing axial direction. Figure 1 , Figure 2 As shown, during measurement, the positions of the capacitive sensor 5 and the electrode sensor 6 maximize the imaging surface of the capacitive sensor 5 and the electrode sensor 6 within the casing, and they are equidistantly distributed, which makes the fluid-related information of the entire wellbore cross section monitored by the instrument richer, the imaging surface wider, and the relevant parameters more accurate.

[0046] To more accurately acquire changes in fluid flow regime and related fluid information, six detection components are used, with each component spaced equally along the axial direction of the housing. Each detection component includes a capacitive sensor 5 and an electrode sensor 6, which are spaced apart, and the spacing between the capacitive sensor 5 and the electrode sensor 6 is equal to the spacing between the detection components.

[0047] In other embodiments, the number of detection components is one, and the detection component includes a capacitive sensor 5. The capacitive sensor 5 is arranged in a ring array coaxial with the sleeve to form a circular imaging surface inside the sleeve.

[0048] In other embodiments, the number of detection components is one, and the detection component includes an electrode sensor 6. The electrode sensor 6 is arranged in a ring array coaxial with the sleeve to form a circular imaging surface inside the sleeve.

[0049] In other embodiments, the number of detection components is one, which includes a capacitive sensor 5 and an electrode sensor 6. The capacitive sensor 5 and the electrode sensor 6 are arranged in a ring array coaxial with the sleeve to form two circular imaging surfaces of equal diameter inside the sleeve.

[0050] In other embodiments, the number of detection components is two, each detection component including a capacitive sensor 5. The capacitive sensors 5 are arranged in a ring array coaxial with the sleeve to form two circular imaging surfaces of equal diameter inside the sleeve.

[0051] In other embodiments, the number of detection components is two, each detection component including an electrode sensor 6. The electrode sensor 6 is arranged in a ring array coaxial with the sleeve to form two circular imaging surfaces of equal diameter inside the sleeve.

[0052] In other embodiments, the number of support structures in a group of support structures can be 4 or 24, and the number of support structures is an even number.

[0053] Example 2 of the horizontal well production profile imaging logging tool of the present invention:

[0054] Based on the above-described technical concept of the present invention, or based on the specific embodiments of the present invention described above, another embodiment is provided below.

[0055] The support structure can be fixed, meaning the distance between the contact rod 4 and the housing in the radial direction remains constant. In this case, if the inner diameter of the casing narrows during the logging tool's entry or exit from the casing, the logging tool may find it inconvenient or even unable to continue moving within the casing, thus preventing measurement. Therefore, in this embodiment, the support structure is preferably an elastically floating structure that floats radially along the housing 1. When the inner diameter of the casing narrows during the logging tool's movement within the casing, the support structure elastically floats closer to the housing 1 in the radial direction, facilitating the logging tool's continued movement within the casing. When the inner diameter of the casing increases, the support structure elastically floats further away from the housing 1 in the radial direction, ensuring the contact rod contacts the inner wall of the casing, maximizing the sensor's imaging surface within the casing.

[0056] Example 3 of the horizontal well production profile imaging logging tool of the present invention:

[0057] Based on the above-described technical concept of the present invention, or based on the specific embodiments of the present invention described above, another embodiment is provided below.

[0058] To facilitate the vertical movement of the transmission support structure along the radial direction of the shell, in this embodiment, as follows: Figure 1 As shown, the support structure includes opposing support rods 3, which are hinged to the contact rod 4 at both ends and form an obtuse angle with the contact rod 4. It also includes opposing sliding structures mounted on the housing 1 and hinged to the end of the support rod 3 away from the contact rod 4, and an elastic structure for providing the sliding structures with axial movement towards each other along the housing 1. Before the logging tool enters the casing, the support structure is in an open state. During the process of the logging tool entering or exiting the casing, when the inner diameter of the casing decreases, the contact rod 4 is subjected to pressure from the casing, causing the support rods 3, hinged at both ends of the contact rod 4, to exert a force on the opposing sliding structures to move away from each other. This achieves the opposite movement of the opposing sliding structures, while simultaneously increasing the distance between the end of the support rod 3 connected to the sliding structure. The support rod 3 then drives the contact rod 4 to move radially upwards towards the housing 1. When the casing diameter increases, the elastic structure provides the opposing sliding structures with axial movement towards each other, and the distance between the end of the support rod 3 connected to the drive device decreases. The support rod 3 then drives the contact rod 4 radially upwards towards the housing 1, away from the housing 1 and closer to the inner wall of the casing, facilitating operation.

[0059] Example 4 of the horizontal well production profile imaging logging tool of the present invention:

[0060] Based on the above-described technical concept of the present invention, or based on the specific embodiments of the present invention described above, another embodiment is provided below.

[0061] The sliding structure can be a slider. Each support rod 3 on the housing 1 has a corresponding groove. The slider is installed in the groove and is hinged to the end of the support rod 3 away from the contact rod 4. A compression spring is provided in the groove. The side of the slider away from the support rod 3 cooperates with one end of the compression spring, and the other end of the compression spring cooperates with the side wall of the groove away from the slider. In use, when the inner diameter of the sleeve decreases, the pressure of the sleeve pushes the contact rod 4 to move radially closer to the housing 1. The support rod 3 pushes the relatively set sliders away from each other and compresses the compression spring, so that the opening degree of the support structure adapts to the inner diameter of the sleeve and then stops. When the inner diameter of the sleeve increases, the compression spring rebounds, and at the same time the sliders move closer to each other, driving the support rod 3 to retract. The contact rod 4 moves radially away from the housing 1, so that the contact rod 4 contacts the inner wall of the sleeve.

[0062] However, the above structure is complex, requiring each support rod to be connected to a slider and a compression spring. Furthermore, when the inner diameter of the sleeve is uneven on the same imaging surface, the imaging surface cannot form a circle, resulting in inaccurate results. Therefore, in this embodiment, the sliding structure is preferably a sliding sleeve. The end of each support rod 3 away from the contact rod 4 is hinged to the corresponding sliding sleeve. The sliding sleeve is looped around the outside of the housing 1. The sliding sleeve consists of an upper sliding sleeve 8 and a lower sliding sleeve 9, which are respectively hinged to the end of their corresponding opposite support rod 3 away from the contact rod 4. The support rod 3 corresponding to the upper sliding sleeve 8 is hinged to the upper sliding sleeve 8, and the support rod 3 corresponding to the lower sliding sleeve 9 is hinged to the lower sliding sleeve 9. Only two opposite sliding sleeves are needed to achieve the hinged connection of all the corresponding opposite contact rods, and the imaging surface can be made circular. The structure is simple and easy to operate.

[0063] Example 5 of the horizontal well production profile imaging logging tool of the present invention:

[0064] Based on the above-described technical concept of the present invention, or based on the specific embodiments of the present invention described above, another embodiment is provided below.

[0065] In this embodiment, as Figure 1 As shown, the elastic structure consists of opposing compression springs, consisting of an upper compression spring 7 and a lower compression spring 10, which are looped around the housing 1. One end of the upper compression spring 7 and the lower compression spring 10 respectively engages with the ends of the upper sliding sleeve 8 and the lower sliding sleeve 9 away from the sensor. The housing 1 has opposing limiting shoulders. The upper compression spring 7 is installed between the end of the upper sliding sleeve 8 away from the sensor and the limiting shoulder, and the lower compression spring 10 is installed between the end of the lower sliding sleeve 9 away from the sensor and the limiting shoulder, and they work together. In use, when the inner diameter of the sleeve decreases, the pressure of the sleeve pushes the contact rod 4 to move radially closer to the housing 1, and drives the distance between the support rod 3 and the housing 1 to increase. This, in turn, pushes the upper sliding sleeve 8 and the lower sliding sleeve 9 away from each other and moves towards the limiting shoulder, while the compression springs are compressed, so that the opening degree of the support structure adapts to the inner diameter of the sleeve and then stops. When the inner diameter of the sleeve increases, the compression springs rebound, and the sliding sleeve drives the support rod 3 to retract, and the contact rod 4 moves radially away from the housing 1, so that the contact rod 4 contacts the inner wall of the sleeve. This structure is simple and easy to operate.

[0066] In other embodiments, the elastic structure can be a tension spring, which is configured between opposing sliding sleeves. During use, when the inner diameter of the sleeve decreases, the pressure of the sleeve pushes the contact rod 4 to move radially closer to the housing 1, and causes the distance between the support rod 3 and the housing 1 to increase. This, in turn, pushes the upper sliding sleeve 8 and the lower sliding sleeve 9 away from each other and pulls the tension spring apart, so that the opening degree of the support structure adapts to the inner diameter of the sleeve and then stops. When the inner diameter of the sleeve increases, the tension spring rebounds, and at the same time, the upper sliding sleeve 8 and the lower sliding sleeve 9 move closer to each other and cause the support rod 3 to retract. The contact rod 4 moves radially away from the housing 1, so that the contact rod 4 contacts the inner wall of the sleeve.

[0067] In this embodiment, the data processing module includes a DSP processor 11 and a storage unit 13, which are connected and housed inside the housing 1. A capacitance sensor 5 and an electrode sensor 6 are connected to the storage unit 13. The collected data from the capacitance sensor 5 and the electrode sensor 6 is stored in the storage unit 13. After processing by the DSP processor 11, the data is transmitted to the ground system. The power module is a high-temperature battery 12. The capacitance sensor 5, the electrode sensor 6, the storage unit 13, and the DSP processor 11 are connected to the high-temperature battery 12, allowing for effective data acquisition even without cable power supply.

[0068] In other embodiments, the data processing module may be just the storage unit 13. The collected data of the capacitive sensor 5 and the electrode sensor 6 are stored in the storage unit 13. After the test is completed, the logging instrument is taken out and the relevant data is read directly from the storage unit 13 for analysis and processing.

[0069] The working principle of this horizontal well production profile imaging logging tool is as follows: Figure 1 , 2 , Figure 3 , Figure 4 As shown, the continuous tubing is connected to the instrument, the instrument is turned on, the contact rod 4 is pressed tightly against the inner wall of the casing, the number of support structures is 12, the support rod 3 has 2 capacitive sensors 5 and 2 electrode sensors 6, which are set at equal intervals. The axial distribution is as follows: the capacitive sensors 5, the electrode sensors 6, the capacitive sensors 5 and the electrode sensors 6 form a circular imaging surface of equal radius. Each sensor measures relevant parameters, and the DSP processor 11 and the storage unit 13 record the dielectric constant of the fluid measured by the capacitive sensor 5 and the conductivity of the fluid measured by the electrode sensor 6 at different positions.

[0070] After the horizontal well production profile imaging logging tool is lowered to the horizontal well section to be monitored, it stops moving and is pulled up for testing. Each sensor measures relevant parameters, and the DSP processor 11 and storage unit 13 record the dielectric constant of the fluid measured by the capacitance sensor 5 and the conductivity of the fluid measured by the electrode sensor 6 at different locations. Based on the different ranges of dielectric constants and conductivity of oil, gas, and water fluids, the differences in dielectric constant between capacitance sensors and conductivity between electrode sensors on the same circumference, and the differences in dielectric constant and conductivity across different circumferences, can be calculated to obtain the water-holding capacity and flow regime imaging of the multiphase flow in the tested horizontal section. Based on the principle that one circumference is 360°, the resolution of the capacitance sensor and electrode sensor system can be calculated to be 360° / 12 = 30°. In other embodiments, the number of support structures can also be 24, resulting in a resolution of 360° / 24 = 15° for the capacitance sensor and electrode sensor system, which has higher angular resolution and more accurate measurement results. In other embodiments, the number of support structures can also be 4, 6, 10, etc., and is an even number, as long as the number of capacitive sensors 5 and electrode sensors 6 can be evenly distributed on a 360° circumference.

[0071] A schematic diagram of the water holdup measurement mode of the horizontal well production profile imaging logging tool is shown below. Figure 4 As shown, specifically:

[0072] For a certain horizontal well, the completed well depth is 4127.0m, the vertical depth is 3077.2m, the horizontal section length is 157.61m, and the artificial bottom is 4088.0m. The oil layer casing has an outer diameter of 139.7mm, a wall thickness of 12.34mm, an inner diameter of 115.02mm, and a depth of 4125.37m. Currently, there is no tubing string in the wellbore; production is done with bare casing. The production profile test section is 3347.0-4038.0m.

[0073] (1) Before the test, the wellbore was treated with “coiled tubing + connector + check valve + safety joint + screw motor + Φ95mm flat-bottomed grinding shoe” to determine the wellbore condition and the depth of obstruction;

[0074] (2) After production stabilizes, production profile testing will be carried out in the production section from 3347.0 to 4038.0 m.

[0075] (3) Assemble the test instrument string according to the test process requirements, connect one end of the instrument to the continuous tubing through thread 2, and transport it to the bottom boundary of the target layer in the lower horizontal section at position 4058.0m, 20m below the bottom.

[0076] (4) When the instrument is turned on, the DSP processor 11 receives the command, the high-temperature battery 12 provides power, the contact rod 4 is in close contact with the inner wall of the sleeve, and the capacitive sensor 5 and the electrode sensor 6 are arranged in a ring array on the side of the contact rod 4 facing the housing 1 to form a circular imaging surface.

[0077] (5) Data acquisition: The instrument starts to lift and measure at a speed of 100-200m / h. Each sensor 4 is uniformly rotated and arranged along the circumference at equal angles to collect three-dimensional information. The relevant data of the capacitance sensor is the collected dielectric constant, the response time of the dielectric constant, and the depth of the capacitance sensor. The relevant data of the electrode sensor is the collected conductivity, the response time of the conductivity, and the depth of the electrode sensor. The data are stored in the storage unit 13.

[0078] (6) Data processing: The collected data is sent to the ground system via storage unit 13 and DSP processor 11 for data processing and analysis. For example... Figure 5 As shown, the dielectric constant is measured by each capacitive sensor 5 and the conductivity is measured by each electrode sensor 6. The water holding capacity and fluid flow state of the fluid in the layer can be obtained by using the bilinear difference method.

[0079] The specific processing and parsing methods are as follows:

[0080] The flowchart for measuring fluid flow regime and water holdup using a horizontal well production profile imaging logging tool is shown below. Figure 5 As shown, the response values ​​between each sensor are first obtained, and then the water holding capacity in the horizontal well is obtained according to the bilinear interpolation method and cross-sectional imaging.

[0081] The logging tool includes 12 support structures. On the support rod 3, 12 capacitive sensors 5, 12 electrode sensors 6, 12 capacitive sensors 5, and 12 electrode sensors 6 are evenly distributed along the circumferential surface of the housing 1. The dielectric constant ε and conductivity σ between two points around each sensor on the circular imaging surface are measured as parameters to determine the conductivity of the fluid on the circumferential surface.

[0082] Taking an electrode sensor on a circular imaging surface as an example, a rectangular coordinate system is established with the center of the circle based on the instrument's circumferential cross-section, forming the coordinate matrix of the electrode sensor. First, 12 electrode sensors are arranged in a ring array coaxial with the sleeve inside the sleeve to form a circular imaging surface, such as... Figure 4 As shown, the 12 electrode sensors are numbered I, II, III...XII. The conductivity σ between two points around the 12 electrode sensors is measured as a parameter to determine the conductivity of the fluid on the circumferential surface. A rectangular coordinate system is established with the center of the instrument's circumferential cross-section to form the coordinate matrix of the electrode sensors.

[0083] Secondly, based on the conductivity measured by the electrode sensors, the midpoint conductivity and midpoint conductivity coordinates between each electrode sensor and other electrode sensors are calculated. The conductivity at the midpoint between these two points is then:

[0084]

[0085] In Equation 1, σ ij V represents the midpoint conductivity. i σ j This represents the conductivity values ​​measured by two electrode sensors, where i and j represent the electrode sensor numbers, and i ≠ j;

[0086] The coordinates of the conductivity at the midpoint are:

[0087]

[0088]

[0089] In Equation 2, r represents the inner circumference radius of the sleeve, n represents the total number of electrode sensors, i and j represent the electrode sensor numbers, i ≠ j, σx ij σy ij This represents the conductivity coordinates at the midpoint.

[0090] Then, based on the midpoint conductivity and its coordinates, a computer is used to traverse all points to obtain a combination of four midpoint conductivity parameter coordinates that conform to bilinear interpolation. Based on the four midpoint conductivity parameter values ​​and their coordinates in each group, the circular imaging surface is meshed using bilinear interpolation to obtain the actual conductivity value at the interpolation point. This actual conductivity value is calculated based on the measured actual conductivity. Therefore, the actual conductivity value at the interpolation point is:

[0091]

[0092] In Equation 3, K i1 K i2 K j1 and K y2 These represent the x and y coordinates of the four known points constituting the current bilinear interpolation in the coordinate matrix of the electrode sensor, which is formed by establishing a rectangular coordinate system around the center of the circular imaging surface. x represents the x-coordinate of the interpolation point, y represents the y-coordinate of the interpolation point, and σ represents the x-coordinate of the interpolation point. ij σ (i+1)j σ i(j+1) σ (i+1)(j+1) This represents the conductivity values ​​of the four known coordinate points that constitute the current bilinear interpolation in the coordinate matrix, where i ≠ j.

[0093] Next, based on the 73 coordinate points obtained by the computer traversing the 12 components and calculating the midpoint conductivity coordinates between the 12 components, there are a total of 1,088,430 combinations. 384 combinations that conform to bilinear interpolation are obtained. Therefore, the circumferential cross-section is divided into 457 grids (73 and 384). Based on the principle that the conductivity ranges of interpolation points differ between oil, gas, and water, the actual conductivity values ​​of the interpolation points are compared with the corresponding conductivity ranges to obtain the number of grids for different phases. These interpolation conductivity ranges refer to the standard conductivity ranges for judging oil, gas, and water. The number of grids with values ​​corresponding to the conductivity ranges of oil, gas, and water in each grid are N, O, and P, respectively. Then, the oil holding capacity Y is obtained according to Equations 4, 5, and 6. o Gas holding rate Y g Water holding capacity Y w :

[0094] Y o =N / M×100% Equation 4

[0095] Y g =O / M×100% Equation 5

[0096] Y w =P / M×100% Equation 6.

[0097] The calculation of data collected from the imaging surfaces of the other electrode sensor and the two capacitor sensor sensors is similar, and so on. When the dielectric constant measured by the capacitor sensor is applied to the above method, based on the principle that the dielectric constant ranges of the interpolation points for oil, gas, and water are different, the actual dielectric constant values ​​of the interpolation points are compared with the dielectric constant ranges of the different corresponding interpolation points to obtain the number of grids for different phases. The dielectric constant range of the interpolation points refers to the standard dielectric constant range for judging oil, gas, and water, and the number of grids in each grid whose values ​​are within the dielectric constant ranges of oil, gas, and water is obtained.

[0098] By mapping all grid values ​​to grayscale pixel values ​​between 0 and 255, the distribution of dielectric constant or conductivity in the sensitive field can be reconstructed, thereby enabling the calculation of oil, gas and water holding capacity and fluid flow imaging.

[0099] (7) Flow calculation. For example... Figure 6 As shown, by recording the capacitance or electrode sensors on different imaging surfaces and measuring the same or closest two sets of dielectric constants or conductivity, the response time interval between each capacitance sensor on the corresponding circular imaging surface or between the electrode sensors on the corresponding circular imaging surface can be determined, and the fluid velocity and flow rate can be calculated.

[0100] The dielectric constant or conductivity of the fluid passing through two circular imaging surfaces is calculated sequentially using capacitive or electrode sensors on different imaging surfaces. The same or closest dielectric constant or conductivity measured at the two circular imaging surfaces is obtained, and the detection time difference of the same or closest dielectric constant or conductivity is determined. Finally, based on the detection time difference and the distance between the two circular imaging surfaces, the fluid velocity is calculated using Equation 7, and the fluid flow rate is calculated using Equation 8.

[0101] Taking an electrode sensor as an example, firstly, the fluid passes through the circular imaging surface formed by the first electrode sensor. When the electrode sensor on the first circular imaging surface collects data in the horizontal segment, the response time is t1, the depth is h1, and σ... 101 …σ 112 To obtain a three-dimensional array A1 based on the conductivity measured by 12 electrode sensors, where...

[0102] Then, the fluid passes through the circular imaging surface formed by the second electrode sensor. The response times of the electrode sensor on the second circular imaging surface that collect data in the horizontal segment are t2, t3, ... t. n , where when t n When the correlation between the time-acquisition array and the first group of electrode sensor acquisition arrays at time t1 is greater than 80%, the three-dimensional array A is obtained. n , And A1∝A n >80%;

[0103] At this point, it is considered that the same fluid flows through the circular imaging surface formed by the two electrode sensors, that is, the same frame cross-section imaging fluid obtains the same or closest conductivity measured at the two circular imaging surfaces.

[0104] Finally, by recording the response times t1 and t2 of the fluid flowing through the circular imaging surface of the two electrode sensors... n Given the distance L between the circular imaging surfaces of the two electrode sensors, the fluid velocity is calculated using Equation 7, and the fluid flow rate is calculated using Equation 8.

[0105]

[0106] In Equation 7, L is the distance between the two circular imaging planes, and t1 and t2 are also given. n The response time of the electrode sensor corresponding to the same or closest conductivity data on two circular imaging surfaces;

[0107] Q = πr 2 V-type 8

[0108] In Equation 8, r is the inner diameter of the casing, and V is the fluid velocity.

[0109] In other embodiments, the above method can be used to sequentially calculate the dielectric constant of the fluid passing through two circular imaging surfaces based on the capacitance sensors on different imaging surfaces, obtain the same or closest dielectric constants calculated at the two circular imaging surfaces, determine the detection time difference of the same or closest dielectric constants, and finally, calculate the fluid velocity using Equation 7 based on the detection time difference and the distance between the two circular imaging surfaces, and calculate the fluid flow rate using Equation 8.

[0110] In other embodiments, the above method can be used to sequentially calculate the dielectric constant of the fluid passing through the two circular imaging surfaces based on the capacitance sensors on different imaging surfaces, and simultaneously calculate the conductivity of the fluid passing through the two circular imaging surfaces based on the electrode sensors on different imaging surfaces. At the same time, the same or closest dielectric constant and conductivity calculated at the circular imaging surfaces of the two capacitance sensors and the two circular imaging surfaces of the two electrode sensors are obtained, and the detection time difference of the same or closest dielectric constant and conductivity is determined. Finally, based on the detection time difference and the distance between the two circular imaging surfaces, the fluid velocity is calculated using Equation 7, and the fluid flow rate is calculated using Equation 8.

[0111] Example 6 of the horizontal well production profile imaging logging tool of the present invention:

[0112] In this embodiment, as Figure 7 As shown, the horizontal well production profile imaging logging tool includes a housing 1, which is cylindrical. The top of the housing 1 has a connector for connecting to coiled tubing, and the tubing and logging tool are connected via threads 2. It also includes 12 support structures, each consisting of support arms 15, which are circumferentially and evenly mounted on the housing 1. Each support arm 15 has a detection component, including an electrode sensor 6, which is fixedly mounted on the support arm 15 near the housing 1. The electrode sensor 6 is arranged in a circular array coaxially with the casing, forming a circular imaging surface within the casing. The horizontal well production profile imaging logging tool also includes a data processing module and a power module, both installed within the housing 1. The data processing module is connected to the electrode sensor 6 and is used to process the acquired data. The power module supplies power to the electrode sensor 6 and the data processing module.

[0113] The electrode sensor 6 can be positioned on the support arm 15 near the housing 1. However, in this case, the imaging surface of the electrode sensor 6 is relatively small within the casing, resulting in less fluid-related information across the entire wellbore cross-section monitored by the instrument, leading to inaccurate results. Therefore, in this embodiment, preferably, the outer end of the support arm 15 has a contact end for contacting the inner wall of the casing, and the electrode sensor 6 is positioned radially near the contact end of the support arm 15. Figure 7 As shown, the contact end is a roller 21 mounted on the support arm 15 at the end position away from the housing 1. During measurement, when the coiled tubing drags the instrument and encounters a decrease or increase in the inner diameter of the casing, the roller 21 can assist in pushing, reducing movement resistance and extending the service life of the support arm 15 and the instrument. The electrode sensor 6 is set on the support arm 15 radially close to the roller 21, which maximizes the imaging surface of the electrode sensor inside the casing. This results in richer fluid-related information across the entire wellbore cross-section monitored by the instrument, a wider imaging surface, and more accurate related parameters.

[0114] In other embodiments, the contact end may be a spherical end fixed to the end of the support arm 15 away from the housing 1.

[0115] In other embodiments, there can be 4 or 24 electrode sensors on the circular imaging surface.

[0116] In other embodiments, the detection component includes a capacitive sensor 5, which is arranged in a ring array coaxial with the sleeve to form a circular imaging surface inside the sleeve.

[0117] In other embodiments, the detection assembly includes a capacitance sensor 5 and an electrode sensor 6. The support arm is a curved structure with a portion parallel to the axial direction of the housing. The capacitance sensor 5 and the electrode sensor 6 are disposed at this portion such that the capacitance sensor 5 and the electrode sensor 6 are arranged in a ring array coaxial with the sleeve, forming two circular imaging surfaces of equal diameter inside the sleeve.

[0118] Example 7 of the horizontal well production profile imaging logging tool of the present invention:

[0119] Based on the specific embodiment 6 of the present invention described above, another embodiment is provided below.

[0120] The support arm 15 can be fixedly installed on the circumferential surface of the housing 1. In this case, the support arm 15 is fixedly installed at a certain angle to the housing 1. When the inner diameter of the casing narrows during the logging tool's entry into the casing, the logging tool may find it inconvenient or even unable to continue moving within the casing. Therefore, in this embodiment, preferably, the support arm 15 is hinged to the housing 1, and the housing 1 is equipped with a holding mechanism that keeps the support arm 15 in an outwardly extended state and an inwardly retracted state. Before the logging tool enters the casing, the holding mechanism can control the support arm 15 to remain in the inwardly retracted state, facilitating the logging tool's entry into and movement within the casing. Once the logging tool enters the casing and reaches the detection position, the holding mechanism controls the support arm 15 to extend and remain in the outwardly extended state, making operation convenient.

[0121] Example 8 of the horizontal well production profile imaging logging tool of the present invention:

[0122] Based on the specific embodiments 6 and 7 of the present invention described above, another embodiment is provided below.

[0123] like Figure 7 , Figure 8 As shown, in this embodiment, the holding mechanism includes a transmission rod 16 arranged along the length of the housing 1. The transmission rod 16 is installed inside the housing 1. The end of the support arm 15 away from the electrode sensor 6 is a bent structure. The housing 1 is provided with a clearance groove. The bent structure is hinged to the housing 1 through its bent portion. The end of the bent structure is hinged to the transmission rod 16 inside the housing 1. The holding mechanism also includes a driving device. The driving device controls the transmission rod 16 to reciprocate linearly along the axial direction of the housing 1, so that the support arm 15 rotates about a direction perpendicular to the axial direction of the housing 1 and expands and retracts radially, so that the support arm 15 swings to the expanded state and the retracted state. When the support arm 15 is in the expanded state, the electrode sensor 6 on the support arm 15 is arranged in a ring array inside the sleeve, forming a circular imaging surface at the position of the support arm 15 near the roller 21 in the radial direction. When the support arm 15 is in the retracted state, the support arm 15 is in the clearance groove on the housing 1 and parallel to the transmission rod 16, which is convenient to operate.

[0124] In this embodiment, the driving device includes an electromagnet 17 and a ferromagnetic component, which is an iron plate 18. A compression spring 19 is installed between the electromagnet 17 and the iron plate 18. The iron plate 18 is fixedly installed inside the housing 1. Both the electromagnet 17 and the compression spring 19 are disposed inside the hollow sleeve 20. One side of the electromagnet 17 is mounted on the transmission rod 16 at the end away from the support arm 15. The side of the electromagnet 17 away from the transmission rod 16 cooperates with the compression spring 19. The end of the compression spring 19 away from the electromagnet 17 cooperates with the iron plate 18. The electromagnet 17 can move axially inside the hollow sleeve 20. One end of the hollow sleeve 20 is fixedly connected to the iron plate 18. The electromagnet 17 is connected to the power module. In use, the power module energizes the electromagnet 17, generating a magnetic force between the electromagnet 17 and the iron plate 18. Under the action of the magnetic force, the electromagnet 17 drives the compression spring 19 to compress towards the iron plate 18. At the same time, the electromagnet 17 drives the transmission rod 16 to move towards the iron plate 18, causing the support arm 15 to swing to the extended state. When it is necessary to retract the support arm 15, the power module is directly de-energized, there is no magnetic force between the electromagnet 17 and the iron plate 18, the compression spring 19 rebounds, and the electromagnet 17 drives the transmission rod 16 to move away from the iron plate 18, causing the support arm 15 to swing to the retracted state. This structure is simple and easy to operate.

[0125] In other embodiments, the positions of electromagnet 17 and iron plate 18 can be interchanged. Iron plate 18 and compression spring 19 are both disposed inside hollow sleeve 20. One side of iron plate 18 is mounted on the transmission rod 16 at the end away from support arm 15. The side of iron plate 18 away from transmission rod 16 cooperates with compression spring 19. The end of compression spring 19 away from iron plate 18 cooperates with electromagnet 17. Iron plate 18 can move axially inside hollow sleeve 20. One end of hollow sleeve 20 is fixedly connected to electromagnet 17. Electromagnet 17 is fixedly installed inside housing 1 and connected to power module. When in use, the power module powers the electromagnet 17, generating a magnetic force between the electromagnet 17 and the iron plate 18. Under the action of the magnetic force, the iron plate 18 drives the compression spring 19 to compress towards the electromagnet 17. At the same time, the iron plate 18 drives the transmission rod 16 to move towards the electromagnet 17, causing the support arm 15 to swing to the extended state. When it is necessary to retract the support arm 15, the power module is directly de-energized, there is no magnetic force between the electromagnet 17 and the iron plate 18, the compression spring 19 rebounds, and at the same time, the iron plate 18 drives the transmission rod 16 to move away from the electromagnet 17, causing the support arm 15 to swing to the retracted state.

[0126] In other embodiments, the ferromagnetic component may be a magnet.

[0127] Example 9 of the horizontal well production profile imaging logging tool of the present invention:

[0128] Based on the specific embodiments 6, 7, and 8 of the present invention described above, another embodiment is provided below.

[0129] Each support arm 15 can be hinged to the same transmission rod 16. However, when there are many support arms 15, a large force is required to control the opening of each support arm 15. If only one transmission rod 16 is used, and only one drive device is installed on it, the support arm 15 may not reach the corresponding unfolded position due to insufficient force provided by the drive device. Therefore, in this embodiment, each support arm 15 is hinged to a corresponding transmission rod 16, and a drive device is installed on each transmission rod 16 to facilitate the unfolding of each support arm 15 and ensure that the support arm 15 reaches the corresponding unfolded position.

[0130] During the measurement process, variations in the casing inner diameter and the instrument's own weight can cause different opening angles for each support arm, leading to errors in the produced profile imaging results. Therefore, in this embodiment, the logging tool also includes a sensor to calculate the opening angle of each support arm 15. This sensor is a displacement sensor 22 mounted on the transmission rod 16, used to measure the linear displacement of the transmission rod 16. The power module is connected to the displacement sensor 22, providing power to it. This allows the displacement of the transmission rod 16 to be recorded by the displacement sensor 22, enabling the calculation of the angle between the support arm 15 and the housing 1. Recording the opening angle of each support arm 15 is used for subsequent correction of the produced profile imaging results. This structure is simple. In other embodiments, an angle sensor can be installed between the support arm 15 and the housing 1 to directly measure the angle between them.

[0131] In this embodiment, an insulating gasket 23 is fixedly installed between the electrode sensor 6 and the support arm 15. The conductivity measured by the electrode sensor 6 on each support arm 15 responds to the fluid information in the wellbore. The electrode sensor 6 is insulated from the support arm 15 and the casing, and does not receive casing conductivity information, making the monitoring results more accurate.

[0132] In order to facilitate the instrument's entry into the casing and to serve as a guide, in this embodiment, a guide cone 14 is provided at the end of the housing 1 that first enters the casing, which at the same time reduces the risk of the instrument encountering obstacles during the well running process, and allows the instrument to be smoothly lowered to the section to be monitored.

[0133] In this embodiment, the data processing module includes a DSP processor 11 and a storage unit 13, which are connected and housed inside the housing 1. Electrode sensors 6 and 22 are connected to the storage unit 13. Data collected from electrode sensors 6 and 22 is stored in the storage unit 13. After processing by the DSP processor 11, the data is transmitted to the ground system. The power module is a high-temperature battery 12. Electrode sensors 6, 22, storage unit 13, and DSP processor 11 are connected to the high-temperature battery 12, allowing for effective data acquisition even without cable power.

[0134] In other embodiments, the data processing module may be a storage unit 13, where the collected data from the electrode sensor 6 and displacement sensor 22 are stored. After the test is completed, the logging instrument is taken out, and the relevant data is read directly from the storage unit 13 for analysis and processing.

[0135] The working principle of this horizontal well production profile imaging logging tool is as follows: Figure 4 , 7 As shown in Figure 8, the coiled tubing is connected to the instrument and lowered into the horizontal well section to be monitored. The instrument is turned on, and the support arm 15 is opened to fit tightly against the inner wall of the casing. There are 12 sets of support arms 15, electrode sensors 6, insulating gaskets 23, rollers 21, and transmission rods 16. The electrode sensors 6 on each support arm 15 form a circular imaging surface near the inner wall of the casing. The DSP processor 11 and storage unit 13 record the conductivity of the fluid measured by the electrode sensors 6 at different locations. At the same time, the displacement sensor 22 measures the linear displacement of the transmission rod 16 and calculates the opening angle of each support arm 15 for imaging result correction. A schematic diagram of the water holdup measurement mode of this horizontal well production profile imaging logging tool is shown below. Figure 9 As shown, the flowchart for measuring water holdup using a horizontal well production profile imaging logging tool is as follows: Figure 5 As shown, the specific processing and analysis method follows the test method for calculating the holdup of horizontal well production profile imaging logging tool described above. First, the response values ​​between each sensor are obtained, and then the holdup of oil, gas and water in the horizontal well is obtained according to the bilinear interpolation method and cross-sectional imaging.

[0136] In this horizontal well production profile imaging logging tool, the 15° opening angle of each support arm is recorded for subsequent production profile imaging result correction. Specifically, the result correction is performed by calculating the support arm radius. Figure 10 As shown, the support rod consists of a long support rod and a short support rod, where the length of the short support rod is A and the length of the long support rod is B. When the instrument support arm 15 is open, the angle between the long support rod and the horizontal direction is β. After the instrument is lowered into the well, changes in the inner diameter of the horizontal section of the casing or the instrument's own weight can cause each support arm to be compressed, resulting in different opening angles. At this time, the displacement sensor 22 measures a displacement of ΔL. The circumference radii formed by each support arm of the instrument are as follows:

[0137] R = A cosβ + r i

[0138] Where, r i =B·sinβ, sinβ=ΔL / A, sinβ=r i / B.

[0139] Example 10 of the horizontal well production profile imaging logging tool of the present invention:

[0140] like Figure 11 As shown, a second instrument is added based on Example 10. The two instruments are connected by thread 2 to measure the fluid flow rate in the horizontal section. The response time interval of each electrode sensor 6 is determined by using the two sets of identical or closest conductivity data measured at the two circular imaging surfaces on the two instruments, and the fluid flow rate can be calculated. The specific processing and analysis methods are carried out according to the calculation method of fluid flow rate measurement of the horizontal well production profile imaging logging tool described above.

[0141] Through the above description of specific embodiments of the horizontal well production profile imaging logging tool of the present invention, it can be seen that the present invention provides a horizontal well production profile imaging logging tool, including a housing and a group of support structures. The support structures are uniformly arranged circumferentially on the housing, and detection components are provided on the support structures. The detection components include a capacitance sensor and / or an electrode sensor. Identical sensors on each support structure are arranged in a ring array coaxial with the casing to form a circular imaging surface inside the casing, and the circular imaging surface is of equal diameter. The logging tool also includes a data processing module connected to the sensors and a power supply module for powering them. The capacitance sensor collects data such as the dielectric constant, the time corresponding to the acquisition of the dielectric constant, and the depth of the capacitance sensor. The electrode sensor collects data such as the conductivity, the time corresponding to the acquisition of the conductivity, and the depth of the electrode sensor. Based on the above data and through calculation, the holdup and fluid flow state of the multiphase flow in the test horizontal section can be obtained, and the fluid flow rate can be calculated. The horizontal well production profile imaging logging tool of this invention does not require flow collection for measurement. This logging tool obtains the true fluid cross-sectional information within the casing through a circular imaging surface formed by capacitive sensors and / or electrode sensors. This ensures that the parameters measured by each sensor are consistent with the parameters of each phase in the actual horizontal well, while simultaneously acquiring more comprehensive fluid response values. This allows for accurate judgment of changes in fluid flow regime, resulting in higher accuracy in calculating the holdup and flow rate of each phase. Furthermore, capacitive sensors are suitable for low water cut conditions, while electrode sensors are suitable for high water cut conditions; their combination makes the test more accurate. This method directly tests based on the phases present in the horizontal well, applicable to the fluid flow regime, holdup, and flow rate testing of any two phases in the oil, water, and gas components of a horizontal well, as well as the fluid flow regime, holdup, and flow rate testing of all three phases. Additionally, the capacitive and electrode sensors have simple structures, higher anti-fouling and anti-sticking capabilities, and are less prone to damage, reducing the probability of instrument failure downhole and improving the logging success rate.

[0142] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. The scope of patent protection of the present invention shall be determined by the claims. Similarly, any equivalent structural changes made based on the description and drawings of the present invention shall also be included within the scope of protection of the present invention.

Claims

1. A horizontal well production profile imaging logging tool, comprising a housing, characterized in that, It also includes a group of support structures, which are uniformly arranged circumferentially on the shell. The support structures are equipped with detection components, which include a capacitive sensor and / or an electrode sensor. The same sensors on each support structure are arranged in a ring array coaxial with the casing to form a circular imaging surface inside the casing. The circular imaging surface is of equal diameter. The logging tool also includes a data processing module connected to the sensors and a power supply module for powering them.

2. The horizontal well production profile imaging logging tool according to claim 1, characterized in that, The support structure includes a contact rod extending axially along the housing, the contact rod being used to contact the inner wall of the sleeve and being able to move axially relative to the inner wall of the sleeve, and the detection component being disposed on the contact rod.

3. The horizontal well production profile imaging logging tool according to claim 2, characterized in that, The number of detection components is 2-6. When the number of detection components is 3 or more, the detection components on the contact rod are arranged at equal intervals along the axial direction of the housing.

4. The horizontal well production profile imaging logging tool according to claim 3, characterized in that, The detection component includes a capacitive sensor and an electrode sensor.

5. The horizontal well production profile imaging logging tool according to claim 4, characterized in that, The capacitive sensor and the electrode sensor are spaced apart, and the spacing between the capacitive sensor and the electrode sensor is equal to the spacing between the detection components.

6. The horizontal well production profile imaging logging tool according to claim 1, characterized in that, The number of the support structures is 4-24 and is an even number.

7. The horizontal well production profile imaging logging tool according to claim 1 or 2, characterized in that, The support structure is an elastic floating structure that floats radially along the shell.

8. The horizontal well production profile imaging logging tool according to claim 7, characterized in that, The support structure includes a support rod arranged opposite to each other, the two ends of the support rod and the contact rod are hinged and form an obtuse angle with the contact rod, and also includes a sliding structure arranged opposite to each other on the housing and hinged to the end of the support rod away from the contact rod, and an elastic structure for providing the sliding structure with the ability to move closer to each other along the axial direction of the housing.

9. The horizontal well production profile imaging logging tool according to claim 8, characterized in that, The sliding structure is a sliding sleeve, and the end of each support rod away from the contact rod is hinged to the corresponding sliding sleeve.

10. The horizontal well production profile imaging logging tool according to claim 9, characterized in that, The elastic structure is a compression spring, and the housing has a limiting shoulder that is disposed opposite to it. The compression spring is installed between the sliding sleeve and the limiting shoulder.

11. The horizontal well production profile imaging logging tool according to claim 1, characterized in that, The support structure is a support arm mounted on the housing. The outer end of the support arm has a contact end for contacting the inner wall of the sleeve. The sensor is located on the support arm radially close to the contact end.

12. The horizontal well production profile imaging logging tool according to claim 11, characterized in that, The support arm is hinged to the housing, which is equipped with a retaining mechanism that keeps the support arm in an outward extended state and an inward retracted state.

13. The horizontal well production profile imaging logging tool according to claim 12, characterized in that, The retaining mechanism includes a transmission rod arranged along the length of the housing, and a drive device for controlling the transmission rod to reciprocate along the axial direction of the housing. The transmission rod is hinged to the support arm and drives the support arm to swing to the extended state and the retracted state when the transmission rod is driven to move linearly by the drive device.

14. The horizontal well production profile imaging logging tool according to claim 13, characterized in that, The drive device includes an electromagnet and a ferromagnetic component. One of the electromagnet and the ferromagnetic component is fixedly installed inside the housing, and the other is fixedly installed at the end of the transmission rod. A compression spring is installed between the electromagnet and the ferromagnetic component.

15. The horizontal well production profile imaging logging tool according to claim 13, characterized in that, Each support arm is equipped with a corresponding retaining mechanism.

16. The horizontal well production profile imaging logging tool according to any one of claims 13-15, characterized in that, The logging tool also includes sensors for measuring the opening angle of each support arm, and the sensors are displacement sensors mounted on the transmission rod.

Images