Method and device for determining flow velocity of fluid in well based on distributed optical fibers

Abstract

The invention provides a method and device for determining the flow velocity of fluid in a well based on distributed optical fibers, and the method comprises the steps: carrying out the filtering processing of the pre-obtained distributed optical fiber sound wave data of a target well, so as to determine a filtering result; determining a velocity spectrum corresponding to the target well according to the filtering result; and determining the fluid velocity in the target well according to the velocity spectrum. Aiming at multiplicity of solution of production profile inversion of distributed optical fiber temperature sensing, firstly, a production logging measurement mode is specifically formulated, and the flow velocity of fluid in a shaft is extracted by collecting distributed optical fiber sound wave sensing data, so that multiplicity of solution of production profile inversion is reduced.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development and production, in particular to the technical field of oil and gas field production logging, and in particular to a method and device for determining the flow velocity of a fluid in a well based on distributed optical fiber. Background Art

[0002] Distributed Temperature Sensing (DTS) is a method that can measure the temperature of the entire well section at one time. It realizes temperature monitoring based on the principle of optical time domain reflectometry (OTDR) and the sensitivity of Raman scattering effect to temperature. It has gradually been applied in production logging, and many DTS-based production profile inversion methods have been generated. These methods have the following technical pain points:

[0003] When the instrument reaches a new measurement point, it will bring in the temperature of the previous measurement point, so the true underground temperature cannot be obtained. In addition, these methods are multi-solution. In order to reduce the multi-solution, technicians generally obtain the wellbore fluid flow rate through distributed fiber optic acoustic sensor measurement, and use the fluid flow rate as a constraint condition for production profile inversion to reduce the multi-solution of production profile inversion.

[0004] The fluid velocity measurement in existing production logging cannot represent the actual fluid velocity of the production layer due to the drag of the instrument. In addition, instrument logging cannot achieve long-term monitoring and can only complete single measurement. Summary of the invention

[0005] One object of the present invention is to provide a method for determining the flow velocity of a fluid in a well based on distributed optical fiber, which method extracts the flow velocity of the fluid in the wellbore by collecting distributed optical fiber acoustic sensor data, thereby reducing the multi-solution of the production profile inversion. Another object of the present invention is to provide a device for determining the flow velocity of a fluid in a well based on distributed optical fiber. Still another object of the present invention is to provide a computer device, which includes a memory and a processor, the memory stores a computer program, and the processor implements the steps of the above-mentioned method for determining the flow velocity of a fluid in a well based on distributed optical fiber when executing the computer program. Still another object of the present invention is to provide a readable medium, on which a computer program is stored, and when the computer program is executed by the processor, the steps of the above-mentioned method for determining the flow velocity of a fluid in a well based on distributed optical fiber are implemented.

[0006] In order to achieve the above objectives, the present invention discloses, on one hand, a method for determining the flow velocity of a fluid in a well based on distributed optical fiber, comprising:

[0007] Performing filtering processing on the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0008] Determine the velocity spectrum corresponding to the target well according to the filtering result;

[0009] The fluid velocity in the target well is determined based on the velocity spectrum.

[0010] In one embodiment, the filtering process of the pre-acquired distributed optical fiber acoustic wave data of the target well includes:

[0011] Determining a low-pass filter required for the filtering process according to historical production data of the target well;

[0012] The distributed optical fiber acoustic wave data is filtered according to the low-pass filter.

[0013] In one embodiment, determining the low-pass filter required for the filtering process according to the historical production data of the target well includes:

[0014] Determine a cutoff frequency range corresponding to the low-pass filter according to the historical production data;

[0015] The low-pass filter is determined according to the cut-off frequency range.

[0016] In one embodiment, determining the velocity spectrum corresponding to the target well according to the filtering result includes:

[0017] Velocity picking is performed on the filtering result to determine the velocity spectrum.

[0018] In one embodiment, performing velocity picking on the filtering result to determine the velocity spectrum includes:

[0019] Determine a speed scanning range and a speed scanning interval according to historical production data of the target well;

[0020] The filtering result is speed-picked according to the speed scanning range and the speed scanning interval to determine the speed spectrum.

[0021] In one embodiment, speed picking is performed on the filtering result according to the speed scanning range and the speed scanning interval to determine the speed spectrum, including:

[0022] Determine a scanning time window according to the speed scanning range and the speed scanning interval;

[0023] The filtering result is subjected to velocity picking according to the scanning time window to determine the velocity spectrum.

[0024] In one embodiment, before filtering the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result, the method further includes:

[0025] The target well is shut in for a preset time so that the formation in the target well is in a stable state.

[0026] The present invention also discloses a device for determining the flow velocity of a fluid in a well based on distributed optical fiber, comprising:

[0027] A filtering result determination module is used to perform filtering processing on the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0028] A velocity spectrum determination module, used to determine the velocity spectrum corresponding to the target well according to the filtering result;

[0029] The fluid mobility determination module is used to determine the fluid velocity in the target well according to the velocity spectrum.

[0030] In one embodiment, the filtering result determination module includes:

[0031] A low-pass filter determination unit, used to determine the low-pass filter required for the filtering process according to the historical production data of the target well;

[0032] A data filtering unit is used to filter the distributed optical fiber acoustic wave data according to the low-pass filter.

[0033] In one embodiment, the low-pass filter determination unit includes:

[0034] A frequency range determining unit, configured to determine a cutoff frequency range corresponding to the low-pass filter according to the historical production data;

[0035] A low-pass filter determination subunit is used to determine the low-pass filter according to the cut-off frequency range.

[0036] In one embodiment, the velocity spectrum determination module includes:

[0037] The velocity spectrum determination unit is used to perform velocity picking on the filtering result to determine the velocity spectrum.

[0038] In one embodiment, the velocity spectrum determining unit includes:

[0039] A scanning parameter determination unit, used to determine a speed scanning range and a speed scanning interval according to the historical production data of the target well;

[0040] A speed picking unit is used to perform speed picking on the filtering result according to the speed scanning range and the speed scanning interval to determine the speed spectrum.

[0041] In one embodiment, the speed pickup unit includes:

[0042] A scanning time window determining unit, used to determine the scanning time window according to the speed scanning range and the speed scanning interval;

[0043] The velocity picking subunit is used to perform velocity picking on the filtering result according to the scanning time window to determine the velocity spectrum.

[0044] In one embodiment, the device for determining the flow rate of fluid in a well based on distributed optical fiber further includes:

[0045] The target well shut-in module is used to shut down the target well to a preset time so that the formation in the target well is in a stable state.

[0046] The present invention also discloses a computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor.

[0047] When the processor executes the program, the method described above is implemented.

[0048] The present invention also discloses a computer readable medium having a computer program stored thereon.

[0049] When the program is executed by a processor, the method described above is implemented.

[0050] From the above description, it can be seen that the method and device for determining the fluid velocity in a well based on distributed optical fiber provided by the embodiment of the present invention first filter the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; then determine the velocity spectrum corresponding to the target well according to the filtering result; finally determine the fluid velocity in the target well according to the velocity spectrum. Aiming at the multi-solution of the inversion of the production profile of distributed optical fiber temperature sensing, the present invention first formulates a production logging measurement plan in a targeted manner, and extracts the wellbore fluid velocity by collecting distributed optical fiber acoustic wave sensing data to reduce the multi-solution of the production profile inversion. BRIEF DESCRIPTION OF THE DRAWINGS

[0051] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0052] Figure 1 A schematic flow chart of a method for determining the flow velocity of a fluid in a well based on distributed optical fiber in Embodiment 1 of the present invention;

[0053] Figure 2This is a flow chart of step 100 of a method for determining a fluid velocity in a well based on distributed optical fiber in Embodiment 1 of the present invention;

[0054] Figure 3 This is a flow chart of step 101 of a method for determining a fluid velocity in a well based on distributed optical fiber in the first embodiment of the present invention;

[0055] Figure 4 It is a flow chart of step 200 of a method for determining a fluid velocity in a well based on distributed optical fiber in the first embodiment of the present invention;

[0056] Figure 5 This is a flow chart of step 201 of a method for determining a fluid velocity in a well based on distributed optical fiber in Embodiment 1 of the present invention;

[0057] Figure 6 This is a flow chart of step 2012 of the method for determining the flow velocity of a fluid in a well based on distributed optical fiber in the first embodiment of the present invention;

[0058] Figure 7 Another schematic flow chart of the method for determining the flow velocity of a fluid in a well based on distributed optical fiber in the first embodiment of the present invention;

[0059] Figure 8 It is a flow chart of a method for determining the flow velocity of a fluid in a well based on distributed optical fiber in the second embodiment of the present invention;

[0060] Fig. 9 is a schematic diagram of a low-pass filter in Embodiment 2 of the present invention;

[0061] Fig.10 This is a schematic diagram of the DAS record extraction results in the production stage in the second embodiment of the present invention;

[0062] Fig.11 It is a schematic diagram of the velocity spectrum of the wellbore fluid in the second embodiment of the present invention;

[0063] Fig.12 It is a structural schematic diagram of a device for determining the flow velocity of a fluid in a well based on distributed optical fiber in Embodiment 3 of the present invention;

[0064] Fig.13 It is a schematic diagram of the structure of an electronic device in Embodiment 4 of the present invention. DETAILED DESCRIPTION

[0065] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0066] In order to make the purpose, technical solution and advantages of the present application more clearly understood, the present application is further described in detail below in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present application and are not used to limit the present application.

[0067] Embodiment 1

[0068] In this embodiment, Figure 1 As shown, a method for determining the flow rate of a fluid in a well based on a distributed optical fiber is provided, which comprises:

[0069] Step 100: filtering the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0070] Distributed Acoustic Sensing (DAS) is a technology used to monitor the internal environment of underground rock formations or wellbores. It uses optical fibers as sensors to obtain information about underground media by measuring acoustic signals in the optical fibers. In the oil and gas industry, distributed optical fiber acoustic logging technology can be used to monitor oil and gas wells, helping to analyze the characteristics of underground rock formations, fluid movement, and underground pressure, thereby optimizing oilfield production and management.

[0071] In distributed fiber optic acoustic logging, the optical fiber at one end is arranged in the wellbore or underground rock formation, usually in a straight or spiral manner. By exciting the acoustic signal in the optical fiber, these signals will propagate along the optical fiber and change due to the influence of the underground rock formation or the internal environment of the wellbore. The changes in the acoustic signal in the optical fiber will be monitored and recorded in real time, and then the analysis of these changes can provide information about the underground rock formation, fluid movement and wellbore status. Distributed fiber optic acoustic logging technology has the following advantages: optical fiber sensors can provide high-resolution monitoring in space and can capture subtle underground changes; they can capture changes in underground events such as rock formation displacement and fluid movement in real time. Fiber can cover a long distance, thereby realizing the monitoring of environmental changes in a large range. Fiber optic sensors are insensitive to electromagnetic interference and are suitable for complex environments.

[0072] Step 200: Determine the velocity spectrum corresponding to the target well according to the filtering result;

[0073] Specifically, a velocity analysis is performed on the acoustic wave profile of the target well according to the filtering result to calculate the velocity spectrum of the wellbore fluid in the target well.

[0074] Step 300: Determine the fluid velocity in the target well according to the velocity spectrum.

[0075] Based on the velocity spectrum, and through human-computer interaction, the velocity is picked (the point with the maximum energy in the velocity spectrum is picked), and the fluid flow velocity at different depths can be obtained.

[0076] From the above description, it can be seen that the method for determining the fluid velocity in a well based on distributed optical fiber provided in an embodiment of the present invention first filters the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; then, the velocity spectrum corresponding to the target well is determined according to the filtering result; finally, the fluid velocity in the target well is determined according to the velocity spectrum. Specifically, the present invention first determines the distributed optical fiber acoustic wave sensing measurement scheme in the production stage; performs low-pass filtering on the distributed optical fiber acoustic wave sensing data to obtain the acoustic wave profile of the wellbore fluid velocity; then performs velocity analysis on the acoustic wave profile to calculate the wellbore fluid velocity spectrum; extracts the velocity profile to determine the fluid velocity in each section of the wellbore.

[0077] In one embodiment, see Figure 2 , step 100 comprises:

[0078] Step 101: determining a low-pass filter required for the filtering process according to the historical production data of the target well;

[0079] The historical production data in step 101 include: bottom hole flowing pressure, target reservoir thickness, original formation pressure and production capacity skin factor.

[0080] Step 102: filtering the distributed optical fiber acoustic wave data according to the low-pass filter.

[0081] The low-pass filter allows low-frequency signals in the distributed optical fiber acoustic wave data to pass through while blocking high-frequency signals, thereby reducing or eliminating high-frequency noise or high-frequency components in the signal.

[0082] Specifically, a cutoff frequency (threshold) is set, and signals below this frequency will be retained, while signals above this frequency will be filtered out or weakened. The cutoff frequency can be adjusted according to the historical production data of different target wells to control the effect of the filter.

[0083] There are various types and designs of low-pass filters, including Butterworth filters, Chebyshev filters, and elliptic filters, etc. Preferably, the embodiment of the present application selects a Chebyshev filter as the low-pass filter.

[0084] In one embodiment, see Figure 3, step 101 comprises:

[0085] Step 1011: determining a cutoff frequency range corresponding to the low-pass filter according to the historical production data;

[0086] For step 1011, the cutoff frequency range corresponding to the low-pass filter may also be determined based on historical production data combined with expert experience;

[0087] Step 1012: Determine the low-pass filter according to the cut-off frequency range.

[0088] Based on the cutoff frequency range in step 1011, a filtering formula is determined for each cutoff frequency range according to certain preset rules (depending on the selected low-pass filter type), and a low-pass filter is determined based on all cutoff frequency ranges and their corresponding filtering formulas.

[0089] In one embodiment, see Figure 4 , step 200 comprises:

[0090] Step 201: performing velocity picking on the filtering result to determine the velocity spectrum.

[0091] Specifically, the stacking velocity or the normal time difference velocity value is calculated based on the normal time difference, and the sonic logging data is analyzed for a common depth point, a survey line, or even a survey area to obtain the optimal velocity.

[0092] In one embodiment, see Figure 5 , step 201 comprises:

[0093] Step 211: determining a speed scanning range and a speed scanning interval according to the historical production data of the target well;

[0094] Preferably, the historical production data in step 2011 include: bottom hole flowing pressure, target reservoir thickness, original formation pressure and production capacity skin factor.

[0095] Step 2012: Perform velocity picking on the filtering result according to the velocity scanning range and the velocity scanning interval to determine the velocity spectrum.

[0096] Specifically, the time it takes for sound waves of different speeds to reach each measurement point is calculated by scanning to determine the velocity spectrum.

[0097] In one embodiment, see Figure 6 , step 2012 includes:

[0098] Step 20121: determining a scanning time window according to the speed scanning range and the speed scanning interval;

[0099] Step 20122: Perform velocity picking on the filtering result according to the scanning time window to determine the velocity spectrum.

[0100] In step 20121 and step 20122, the time it takes for sound waves of different speeds to arrive at each measurement point is calculated by scanning, and then a time window of length T is opened at the arrival time, and the average energy of the sound waves in the time window is calculated to obtain the velocity spectrum.

[0101] In one embodiment, see Figure 7 In the method for determining the flow rate of fluid in a well based on distributed optical fiber, before step 100, the method includes:

[0102] Step 90: shutting in the target well for a preset time to keep the formation in the target well in a stable state.

[0103] Preferably, the preset time in step 90 is 48 hours, that is, the target well needs to be shut in for 48 hours before the distributed optical fiber production acoustic logging is performed.

[0104] From the above description, it can be seen that the method for determining the flow rate of fluid in a well based on distributed optical fiber provided in the embodiment of the present invention obtains the distributed optical fiber acoustic sensor data during production through a specific logging data acquisition scheme, and extracts the flow rate of fluid in the wellbore through data processing. The calculation process of this method is simple and efficient. The fluid flow rate determined by the method for determining the flow rate of fluid in a well based on distributed optical fiber provided in the embodiment of the present invention can provide constraint information for the inversion of distributed optical fiber production logging, thereby reducing the multi-solution of the inversion.

[0105] Embodiment 2

[0106] In order to further illustrate the solution, the present invention also takes production logging as an example to provide a specific application example of a method for determining the flow rate of a fluid in a well based on distributed optical fiber. Specifically, Figure 8 As shown, the specific application example includes the following steps:

[0107] It is understandable that production logging is an effective means to understand the production contribution rate of each production section during the exploration and development of oil and gas fields. Through production logging, the production contribution rate of each production layer can be grasped in a timely manner, which is crucial to improving the recovery rate of oil and gas fields. Commonly used production logging methods mainly include production profile production logging (determining the production of each production layer based on instrument measurement), but this instrument production logging has the following problems. First, the instrument size is limited, and it can only measure the production profile within a limited range each time. In order to obtain the production profile of the entire well, it is necessary to use towing equipment to complete the production profile logging of the entire well.

[0108] S1: Measure pipeline acoustic wave data during the production phase of the target well.

[0109] During the production process of the target well, the well is first shut down to stabilize the underground formation; after being shut down for 48 hours, the well is opened for production, and the distributed fiber optic acoustic wave data of the entire well section under the production system is measured. Then the well is shut down for another 48 hours, and after the wellbore fluid is stable, the well is opened again to measure the distributed fiber optic acoustic wave data of the entire well section under the production system. That is, the distributed fiber optic acoustic wave sensing data of the well opening stage is obtained by using the combined operation of shutting down and opening the well.

[0110] S2: Extraction of acoustic profiles from distributed fiber optic acoustic sensors.

[0111] The obtained distributed fiber acoustic wave data is filtered. Fig. 9 ), filtering out the sound wave records with a frequency band range of 0 to 1 Hz. The mathematical expression of the low-pass filter H(f) is:

[0112]

[0113] Where F is the cutoff frequency of the low-pass filter. Based on the filtering principle, in order to avoid the Gibbs phenomenon caused by filtering, the high cutoff frequency f of the low-pass filter is set h It can be calculated by the following formula:

[0114] f h =0.9×F (2)

[0115] The distributed optical fiber acoustic wave data is filtered using the above filter to obtain the acoustic wave profile of the low-frequency distributed optical fiber acoustic wave data, that is, the DAS record in the production stage, see Fig.10 .

[0116] S3: Construct velocity spectrum.

[0117] Specifically, the velocity analysis is performed on the low-frequency distributed fiber acoustic wave data to calculate the velocity spectrum. The acoustic wave record s(t,x) represents the data measured at the depth x at time t, and the velocity analysis is performed using the following formula.

[0118] x j =x 0 +vt,j=1,2,…M (3)

[0119] where x 0 and x j It is known that x j represents the depth of the jth measurement point, and v is the velocity. By setting the scanning range of velocity v [v min ,v max] and scanning interval Δv, calculate the time it takes for sound waves of different speeds to arrive at each measurement point by scanning, then open a time window of length T at the arrival time, calculate the average energy of the sound waves in the time window, and obtain the velocity spectrum. The average energy calculation formula is as follows:

[0120]

[0121] is the number of sample points in the signal continuation window.

[0122] S4: Determine the fluid flow rate at each depth of the target well according to the velocity spectrum.

[0123] See also Fig.11 By picking up the place with the maximum energy (or medium-strong energy group) corresponding to each depth point in the velocity spectrum in a human-computer interactive way, and picking up the fluid velocity, the fluid velocity at different depths can be obtained, that is, the fluid flow rate at various locations in the wellbore.

[0124] From the above description, it can be seen that the method for determining the fluid velocity in a well based on distributed optical fiber provided in an embodiment of the present invention first filters the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; then, the velocity spectrum corresponding to the target well is determined according to the filtering result; finally, the fluid velocity in the target well is determined according to the velocity spectrum. Specifically, the present invention first determines the distributed optical fiber acoustic wave sensing measurement scheme in the production stage; performs low-pass filtering on the distributed optical fiber acoustic wave sensing data to obtain the acoustic wave profile of the wellbore fluid velocity; then performs velocity analysis on the acoustic wave profile to calculate the wellbore fluid velocity spectrum; extracts the velocity profile to determine the fluid velocity in each section of the wellbore.

[0125] The greatest benefit of the present invention over the prior art is that, in the production logging stage, the distributed optical fiber acoustic sensor data of production is obtained through a specific data acquisition scheme, and the wellbore fluid velocity is extracted through data processing, thereby providing constraint information for the distributed optical fiber production logging inversion and reducing the multiple solutions of the inversion.

[0126] Embodiment 3

[0127] Based on the same principle, this embodiment also discloses a device for determining the flow rate of fluid in a well based on distributed optical fiber. Fig.12 As shown, in this embodiment, the device includes:

[0128] A filtering result determination module 10 is used to perform filtering processing on the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0129] A velocity spectrum determination module 20, configured to determine a velocity spectrum corresponding to the target well according to the filtering result;

[0130] The fluid mobility determination module 30 is used to determine the fluid velocity in the target well according to the velocity spectrum.

[0131] In one embodiment, the filtering result determination module includes:

[0132] A low-pass filter determination unit, used to determine the low-pass filter required for the filtering process according to the historical production data of the target well;

[0133] A data filtering unit is used to filter the distributed optical fiber acoustic wave data according to the low-pass filter.

[0134] In one embodiment, the low-pass filter determination unit includes:

[0135] A frequency range determining unit, configured to determine a cutoff frequency range corresponding to the low-pass filter according to the historical production data;

[0136] A low-pass filter determination subunit is used to determine the low-pass filter according to the cut-off frequency range.

[0137] In one embodiment, the velocity spectrum determination module includes:

[0138] The velocity spectrum determination unit is used to perform velocity picking on the filtering result to determine the velocity spectrum.

[0139] In one embodiment, the velocity spectrum determining unit includes:

[0140] A scanning parameter determination unit, used to determine a speed scanning range and a speed scanning interval according to the historical production data of the target well;

[0141] A speed picking unit is used to perform speed picking on the filtering result according to the speed scanning range and the speed scanning interval to determine the speed spectrum.

[0142] In one embodiment, the speed pickup unit includes:

[0143] A scanning time window determining unit, used to determine the scanning time window according to the speed scanning range and the speed scanning interval;

[0144] The velocity picking subunit is used to perform velocity picking on the filtering result according to the scanning time window to determine the velocity spectrum.

[0145] In one embodiment, the device for determining the flow rate of fluid in a well based on distributed optical fiber further includes:

[0146] The target well shut-in module is used to shut down the target well to a preset time so that the formation in the target well is in a stable state.

[0147] From the above description, it can be seen that the device for determining the fluid velocity in a well based on distributed optical fiber provided by an embodiment of the present invention first filters the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; then, the velocity spectrum corresponding to the target well is determined according to the filtering result; finally, the fluid velocity in the target well is determined according to the velocity spectrum. Specifically, the present invention first determines the distributed optical fiber acoustic wave sensing measurement scheme in the production stage; performs low-pass filtering on the distributed optical fiber acoustic wave sensing data to obtain the acoustic wave profile of the wellbore fluid velocity; then performs velocity analysis on the acoustic wave profile to calculate the wellbore fluid velocity spectrum; extracts the velocity profile to determine the fluid velocity in each section of the wellbore.

[0148] Embodiment 4

[0149] The embodiment of the present application also provides a specific implementation of an electronic device capable of implementing all steps in the method for determining the flow rate of a fluid in a well based on a distributed optical fiber in the above embodiment, see Fig.13 , electronic equipment specifically includes the following:

[0150] Processor (processor) 1201, memory (memory) 1202, communication interface (CommunicationsInterface) 1203 and bus 1204;

[0151] The processor 1201, the memory 1202, and the communication interface 1203 communicate with each other via the bus 1204; the communication interface 1203 is used to realize information transmission between related devices such as server-side devices, computing units, and client devices.

[0152] The processor 1201 is used to call the computer program in the memory 1202. When the processor executes the computer program, all the steps in the method for determining the flow velocity of a fluid in a well based on a distributed optical fiber in the above embodiment are implemented. For example, when the processor executes the computer program, the following steps are implemented:

[0153] Step 100: filtering the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0154] Step 200: Determine the velocity spectrum corresponding to the target well according to the filtering result;

[0155] Step 300: Determine the fluid velocity in the target well according to the velocity spectrum.

[0156] Embodiment 5

[0157] The embodiments of the present application also provide a computer-readable storage medium capable of implementing all the steps of the method for determining the flow rate of a fluid in a well based on a distributed optical fiber in the above embodiment. The computer-readable storage medium stores a computer program. When the computer program is executed by a processor, all the steps of the method for determining the flow rate of a fluid in a well based on a distributed optical fiber in the above embodiment are implemented. For example, when the processor executes the computer program, the following steps are implemented:

[0158] Step 100: filtering the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result;

[0159] Step 200: Determine the velocity spectrum corresponding to the target well according to the filtering result;

[0160] Step 300: Determine the fluid velocity in the target well according to the velocity spectrum.

[0161] Each embodiment in this specification is described in a progressive manner, and the same or similar parts between the embodiments can be referred to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the hardware + program embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiment.

[0162] The above is a description of a specific embodiment of the specification. Other embodiments are within the scope of the appended claims. In some cases, the actions or steps recorded in the claims can be performed in an order different from that in the embodiments and still achieve the desired results. In addition, the processes depicted in the drawings do not necessarily require the specific order or continuous order shown to achieve the desired results. In some embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0163] Those skilled in the art will appreciate that embodiments of the present invention may be provided as methods, systems, or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0164] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0165] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0166] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 The steps for the functions specified in one or more boxes.

[0167] The present invention uses specific embodiments to illustrate the principles and implementation methods of the present invention. The description of the above embodiments is only used to help understand the method of the present invention and its core idea. At the same time, for those skilled in the art, according to the idea of ​​the present invention, there will be changes in the specific implementation methods and application scope. In summary, the content of this specification should not be understood as a limitation on the present invention.

Claims

1. A method for determining fluid velocity in a well based on distributed optical fiber, characterized in that: include: Performing filtering processing on the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; Determine the velocity spectrum corresponding to the target well according to the filtering result; The fluid velocity in the target well is determined based on the velocity spectrum.

2. The method for determining the flow velocity of a fluid in a well according to claim 1, characterized in that: The filtering process of the pre-acquired distributed optical fiber acoustic wave data of the target well includes: Determining a low-pass filter required for the filtering process according to historical production data of the target well; The distributed optical fiber acoustic wave data is filtered according to the low-pass filter.

3. The method for determining the flow velocity of a fluid in a well according to claim 2, characterized in that: Determining the low-pass filter required for the filtering process according to the historical production data of the target well includes: Determine a cutoff frequency range corresponding to the low-pass filter according to the historical production data; The low-pass filter is determined according to the cut-off frequency range.

4. The method for determining the flow velocity of a fluid in a well according to claim 1, characterized in that: Determining the velocity spectrum corresponding to the target well according to the filtering result includes: Velocity picking is performed on the filtering result to determine the velocity spectrum.

5. The method for determining the flow rate of fluid in a well according to claim 4, characterized in that: Performing velocity picking on the filtering result to determine the velocity spectrum includes: Determine a speed scanning range and a speed scanning interval according to historical production data of the target well; The filtering result is speed-picked according to the speed scanning range and the speed scanning interval to determine the speed spectrum.

6. The method for determining the flow velocity of a fluid in a well according to claim 5, characterized in that: The filtering result is speed-picked according to the speed scanning range and the speed scanning interval to determine the speed spectrum, including: Determine a scanning time window according to the speed scanning range and the speed scanning interval; The filtering result is subjected to velocity picking according to the scanning time window to determine the velocity spectrum.

7. The method for determining the flow velocity of a fluid in a well according to any one of claims 1 to 6, characterized in that: Before filtering the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result, the method further includes: The target well is shut in for a preset time so that the formation in the target well is in a stable state.

8. A method and device for determining fluid velocity in a well based on distributed optical fiber, characterized in that: include: A filtering result determination module is used to perform filtering processing on the pre-acquired distributed optical fiber acoustic wave data of the target well to determine the filtering result; A velocity spectrum determination module, used to determine the velocity spectrum corresponding to the target well according to the filtering result; The fluid mobility determination module is used to determine the fluid velocity in the target well according to the velocity spectrum.

9. A computer device comprising a memory and a processor, wherein the memory stores a computer program, wherein: When the processor executes the computer program, the steps of the method according to any one of claims 1 to 7 are implemented.

10. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by a processor, the steps of the method according to any one of claims 1 to 7 are implemented.

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