Method, device and equipment for measuring liquid inlet quantity and storage medium

Abstract

This application discloses a method, apparatus, equipment, and storage medium for measuring fracturing fluid injection volume, belonging to the field of exploration technology. The method includes: acquiring sensor signals via a DAS during fracturing operations; the sensor signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations at at least two fracturing depths, the perforations being used to pump fracturing fluid; based on the sensor signals, calculating the energy percentage of the acoustic signal corresponding to the i-th perforation among the at least two perforations; the energy percentage is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, the total energy value being the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy percentage is used to indicate the injection volume percentage of the i-th perforation, where i is an integer; calculating the injection volume of the i-th perforation based on the fracturing fluid discharge rate of the fracturing well and the energy percentage; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fracturing well per unit time.

Description

Technical Field

[0001] This application relates to the field of exploration technology, and in particular to a method, apparatus, equipment and storage medium for measuring liquid inflow. Background Technology

[0002] Fiber optic sensing technology uses optical fibers as sensing elements to measure and analyze the propagation, interference, and scattering characteristics of light signals in optical fibers, thereby enabling precise detection and monitoring of environmental parameters, physical quantities, and chemical indicators.

[0003] With the rapid development of fiber optic sensing technology, fiber optic sensing has begun to be applied to well geophysical exploration, enabling high-density downhole monitoring of the entire well section. The use of fiber optic sensing to monitor hydraulic fracturing operations and evaluate the sand injection and fluid introduction effects of each cluster has already shown initial success.

[0004] However, the data processing and analysis of distributed acoustic sensing (DAS) for fiber optic fracturing monitoring is still in its early stages. There is a lack of effective technical means to calculate the sand injection and fluid injection volume of each perforation in the well and to quantitatively understand the reservoir stimulation effect. Summary of the Invention

[0005] This application provides a method, apparatus, device, and storage medium for measuring fluid inlet volume, which can measure the fluid inlet volume of fracturing perforations based on DAS sensor signals. The technical solution is as follows:

[0006] According to one aspect of this application, a method for measuring the liquid inflow rate is provided, the method comprising:

[0007] During fracturing operations, sensing signals are acquired by a distributed optical fiber acoustic sensor (DAS); the sensing signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations at at least two fracturing depths, the perforations being used to pump fracturing fluid;

[0008] Based on the sensing signal, the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations is calculated; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer;

[0009] Based on the fracturing fluid discharge rate of the fractured well and the energy ratio, the fluid injection rate of the i-th perforation is calculated; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fractured well per unit time.

[0010] According to one aspect of this application, a device for measuring the liquid inflow rate is provided, the device comprising:

[0011] A sensing module is used to acquire sensing signals through a distributed optical fiber acoustic sensor (DAS) during fracturing operations; the sensing signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations at at least two fracturing depths, the perforations being used to pump fracturing fluid;

[0012] The calculation module is used to calculate the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the sensing signal; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer;

[0013] The calculation module is used to calculate the injection volume of the i-th perforation based on the fracturing fluid discharge rate of the fracturing well and the energy ratio; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fracturing well per unit time.

[0014] According to another aspect of this application, a computer device is provided, the computer device including a processor and a memory, the memory storing at least one instruction, at least one program, code set or instruction set, the at least one instruction, the at least one program, the code set or instruction set being loaded and executed by the processor to implement the liquid inlet measurement method as described above.

[0015] According to another aspect of this application, a computer-readable storage medium is provided, wherein at least one instruction, at least one program, code set, or instruction set is stored therein, wherein the at least one instruction, the at least one program, the code set, or the instruction set is loaded and executed by a processor to implement the liquid inlet measurement method as described above.

[0016] According to another aspect of this application, a computer program product or computer program is provided, comprising computer instructions stored in a computer-readable storage medium. A processor of a computer device reads the computer instructions from the computer-readable storage medium and executes the computer instructions, causing the computer device to perform the liquid inlet measurement method provided in various alternative implementations of the above aspects.

[0017] The beneficial effects of the technical solution provided in this application include at least the following:

[0018] Distributed fiber optic acoustic sensors are used to monitor the fracturing operation process and acquire acoustic signals at various fracturing depths within the fracturing well. Based on the energy ratio of the acoustic signal at the perforation depth to the total energy of the acoustic signal, the proportion of fluid injection at that perforation to the total fluid injection is determined. Furthermore, the fluid injection rate of that perforation is calculated based on the fracturing well's drainage rate, thus enabling a quantitative evaluation of the reservoir stimulation effect. Attached Figure Description

[0019] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0020] Figure 1 This is a schematic diagram of the structure of a DAS system provided in an exemplary embodiment of this application;

[0021] Figure 2 This is a flowchart of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0022] Figure 3 This is a flowchart of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0023] Figure 4 This is a schematic diagram of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0024] Figure 5 This is a schematic diagram of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0025] Figure 6 This is a schematic diagram of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0026] Figure 7 This is a schematic diagram of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0027] Figure 8 This is a schematic diagram of a liquid inlet measurement method provided in an exemplary embodiment of this application;

[0028] Figure 9 This is a schematic diagram of the structure of a liquid inlet measurement device provided in an exemplary embodiment of this application;

[0029] Figure 10 This is a schematic diagram of the structure of a computer device provided in an exemplary embodiment of this application.

[0030] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with this application and, together with the description, serve to explain the principles of this application. Detailed Implementation

[0031] To make the objectives, technical solutions, and advantages of this application clearer, the embodiments of this application will be described in further detail below with reference to the accompanying drawings.

[0032] Figure 1 The illustration shows a schematic diagram of a DAS system provided in an exemplary embodiment of this application. The DAS system may include a DAS device 101 and an optical fiber 107 connected to the DAS device 101.

[0033] For example, the liquid inlet measurement method shown in this application embodiment can be applied to a DAS device 101, which runs a liquid inlet measurement application 102. The DAS device 101 can consist of a DAS and a computer device. The DAS includes an optical fiber 107. The computer device can run the liquid inlet measurement application 102. The computer device is used to receive and process the scattered signals detected by the DAS to obtain sensing signals. The computer device can also run the liquid inlet measurement application 102 to calculate the liquid inlet volume of each perforation based on the sensing signals.

[0034] Optionally, the computer device includes a first memory and a first processor. The first memory stores a liquid inlet volume measurement program; the liquid inlet volume measurement program is invoked and executed by the first processor to implement the liquid inlet volume measurement method provided in this application. The first memory may include, but is not limited to, the following: Random Access Memory (RAM), Read Only Memory (ROM), Programmable Read-Only Memory (PROM), Erasable Programmable Read-Only Memory (EPROM), and Electrically Erasable Programmable Read-Only Memory (EEPROM). The first processor may consist of one or more integrated circuit chips. Optionally, the first processor may be a general-purpose processor, such as a Central Processing Unit (CPU) or a Network Processor (NP). Optionally, the first processor can implement the liquid inlet volume measurement method provided in this application by running a program or code.

[0035] An optical fiber 107 is installed in the fractured well 105. The DAS device 101 can send optical signals to the optical fiber 107. The optical signal propagates along the optical fiber in the fractured well 105. Affected by the acoustic vibration generated by fracturing, the optical signal generates a scattered signal. The DAS device 101 receives the scattered signal through the optical fiber 107 to obtain the sensing signal. Perforations 106 (or perforation clusters) are opened at different fracturing depths in the fractured well 105. The perforations 106 are used to pump fracturing fluid to form fractures in the formation.

[0036] The DAS device 101 acquires sensing signals via optical fiber 107, including acoustic signals at different fracturing depths. Based on these signals, the DAS device 101 effectively identifies the vibrations of proppant injection at the perforation site through filtering and high-precision processing. Based on the acoustic signal at the fracturing depth of the perforation in the sensing signals, the energy percentage corresponding to that perforation is calculated to characterize the proppant injection intensity of each downhole perforation. Combined with the fracturing fluid discharge at the wellhead, the proppant injection volume at each perforation location is quantitatively calculated, enabling a quantitative evaluation of the reservoir stimulation effect.

[0037] Figure 2 This is a schematic flowchart illustrating a method for measuring liquid inflow volume according to an exemplary embodiment of this application. This method can be used for, for example... Figure 1 In the DAS device shown, the method includes the following steps.

[0038] Step 210: During the fracturing operation, sensor signals are acquired through DAS; the sensor signals include acoustic signals measured at different fracturing depths; DAS is installed inside the fracturing well; the fracturing well includes at least two perforations installed at at least two fracturing depths, the perforations being used to pump fracturing fluid.

[0039] The optical fiber of the DAS device is installed in the fracturing well to detect acoustic signals at multiple fracturing depths. Multiple perforations are located in the fracturing well, with different perforations (or perforation clusters) situated at different fracturing depths. A perforation can also be called a perforation cluster; in this embodiment, one or more perforations located at the same fracturing depth are referred to as a single perforation or perforation cluster.

[0040] For example, DAS equipment can detect acoustic signals at intervals of 1 meter within a range of 10 to 100 meters downhole. If the first perforation is located at 55 meters downhole and the second perforation is located at 66 meters downhole, then the acoustic signal corresponding to the first perforation at a fracturing depth of 55 meters corresponds to the acoustic signal corresponding to the second perforation at a fracturing depth of 66 meters.

[0041] For example, considering the severe low-frequency noise interference in the wellbore during the sand injection and fluid injection process, an ultra-high frequency (UHF) acquisition parameter of 1-2000Hz can be set to monitor the DAS sensor signal during fracturing and acquire the downhole high-frequency signal.

[0042] Step 220: Based on the sensor signal, calculate the energy ratio of the acoustic signal corresponding to the i-th perforation in at least two perforations; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer.

[0043] The i-th perforation can be any perforation located within the fractured well. That is, using the method provided in this application, the fluid injection rate of each perforation within the fractured well can be calculated. Assuming each perforation is located at position i, and there are a total of n perforations, the energy percentage Ri(t) of each perforation is calculated:

[0044]

[0045] Among them, R i (t) represents the energy percentage of the i-th perforation at time t; S i (t) represents the acoustic energy of the acoustic signal corresponding to the i-th perforation at each time point; n is the number of perforation clusters; t is the fracturing operation time.

[0046] Step 230: Based on the fracturing fluid discharge rate and energy ratio of the fractured well, calculate the fluid injection rate of the i-th perforation; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fractured well per unit time.

[0047] For example, the fluid inflow rate of the i-th perforation is equal to the fracturing fluid discharge rate multiplied by the energy percentage corresponding to the i-th perforation.

[0048] Assuming that the energy injected into the wellbore at each time point is absorbed by the perforations, the energy percentage of each perforation at each time point can represent the relative fluid injection volume of each perforation. Therefore, the fluid injection volume of each perforation is the integral of the fracturing flow rate and the energy percentage of each perforation.

[0049]

[0050] Among them, P i D(t) represents the fluid inflow rate of the i-th perforation during fracturing operation time t; D(t) represents the fracturing fluid discharge rate at each time point.

[0051] In summary, the method provided in this embodiment utilizes distributed fiber optic acoustic sensors to monitor the fracturing operation process, acquires acoustic signals at various fracturing depths within the fracturing well, and determines the proportion of fluid injection rate of the perforation to the total fluid injection rate based on the energy ratio of the acoustic signal at the perforation depth to the total energy of the acoustic signal. Furthermore, it calculates the fluid injection rate of the perforation based on the fracturing well's nighttime drainage rate, thereby achieving a quantitative evaluation of the reservoir stimulation effect.

[0052] An exemplary embodiment for calculating the energy percentage is provided.

[0053] For example, Figure 3 This is a schematic flowchart illustrating a method for measuring liquid inflow volume according to an exemplary embodiment of this application. This method can be used for, for example... Figure 1 The DAS device shown is based on... Figure 2 In the illustrated embodiment, step 220 includes steps 221 to 223.

[0054] Step 210: During the fracturing operation, sensor signals are acquired through DAS; the sensor signals include acoustic signals measured at different fracturing depths; DAS is installed inside the fracturing well; the fracturing well includes at least two perforations installed at at least two fracturing depths, the perforations being used to pump fracturing fluid.

[0055] For example, the acoustic vibration energy downhole during fracturing operations is monitored using DAS. Assuming the fracturing time is t and the wellbore depth is h, the magnitude of the acoustic vibration (i.e., the acoustic signal) monitored by DAS at each depth and at each time is x(h,t).

[0056] Step 221: The signal in the target frequency band of the sensing signal is determined as the target frequency band signal, and the noise interference of the sensing signal in the target frequency band is minimized.

[0057] To reduce noise interference in the sensing signal, the sensing signal can be frequency-divided, and the frequency band with the least noise can be selected for subsequent analysis. Optionally, the sensing signal can be divided into at least one frequency band corresponding to each frequency band; the frequency band signal with the least noise among the at least one frequency band signal can be determined as the target frequency band signal, and the target frequency band signal is the frequency band division signal of the target frequency band.

[0058] For example, high-frequency signals are extracted from the sensor signals through filtering to represent the sand injection and liquid inlet signals near each perforation. The extracted frequencies are typically 1000-2000Hz, i.e., f1 = 1000Hz, f2 = 2000Hz. Therefore, the high-frequency signal extracted at each depth h during the sand injection and liquid inlet process is x. h (t).

[0059] x h (t)=F -1 [X(f)*G(f)]

[0060] The expression for the bandpass filter G(f) is:

[0061]

[0062] Where f is the frequency of the sensing signal, in Hertz (Hz); f0 is the center frequency of the filter window, in Hertz (Hz); u is the standard deviation of the Gaussian function; A is a constant; σ is the impulse function; and G(f) is the Gaussian filter window.

[0063] Repeat step 221 to filter the acoustic vibration x(h,t) at each depth to obtain the downhole sand injection signal X(h,t). Figure 4 These are frequency division signals 401 (0-50Hz), 402 (50-100Hz), 403 (100-1000Hz), and 404 (1000-2000Hz). Within the fracturing depth range of 300-500m where the perforation is located... Figure 4 Within the white dashed box in the image, the frequency division signal in the 100-1000Hz band has the least interference; therefore, the sensor signal in the 100-1000Hz band is selected for analysis.

[0064] Step 222: Perform median filtering on the target frequency band signal to obtain the median filtered signal.

[0065] To further improve energy focusing near the perforation, the original data X(h,t) is subjected to further median filtering. A sliding window is used to traverse the target frequency band signal according to the sliding step size. The energy value at the location of the sliding window is determined as the median of all energy values ​​within the sliding window, thus obtaining the median-filtered signal.

[0066] For example, the target frequency band signal 405 of the sensing signal Figure 5 As shown. Assuming the coordinates are (h, t), a window of size m×n is represented as S. ht Based on the data X(h,t), select window S ht Given the data g(h,t), calculate the median of this data and output it as the coordinate point (h,t). This is the two-dimensional median filtered signal 406. Figure 6 As shown.

[0067] f(h,t)=median[g(h,t)](h,t)∈S ht

[0068] Where f(h,t) is the median filtered signal; g(h,t) is the target frequency band signal; and median[g(h,t)] is the value of S. ht The median energy of the target frequency band signal within the window.

[0069] Step 223: Based on the median filtered signal, calculate the energy percentage of the acoustic signal corresponding to the i-th perforation in at least two perforations.

[0070] For example, the median filtered signal includes a first time period, which includes time t; the product of the fracturing fluid discharge rate at time t and the energy ratio of the i-th perforation at time t is determined as the fluid inflow rate of the i-th perforation at time t; the sum of the fluid inflow rates of the i-th perforation at each time within the first time period is calculated to obtain the fluid inflow rate of the i-th perforation within the first time period.

[0071] Based on step 222, high signal-to-noise ratio and high-focusing proppant injection signals (i.e., median-filtered signals) within a downhole fracturing time t can be effectively extracted. Further, based on the median-filtered signals, the proppant injection rate for each perforation is calculated, and the energy ratio of each perforation location to the total acoustic energy is extracted. Assuming there are n perforation locations, the energy ratio R for the i-th perforation is calculated. i (t):

[0072]

[0073] Among them, S i (t) represents the energy of the acoustic signal of the i-th perforation at each time point t; n represents the total number of perforations; and t represents the fracturing operation time.

[0074] Step 230: Calculate the injection rate of the i-th perforation based on the fracturing fluid discharge rate and energy ratio of the fracturing well; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fracturing well per unit time.

[0075] For example, for time t in the median filtered signal and the i-th perforation among at least two perforations, the ratio of the energy value of the i-th perforation at time t to the total energy value at time t is calculated to obtain the energy proportion of the i-th perforation at time t; t and i are positive integers; wherein, the i-th perforation corresponds to the i-th fracturing depth, and the energy value of the i-th perforation at time t is the energy value of time t and the i-th fracturing depth in the median filtered signal; the total energy value at time t is the sum of the energy values ​​of at least two perforations at time t.

[0076] Multiplying the energy percentage of the i-th perforation at time t by the fracturing fluid discharge rate at time t yields the fluid inflow rate of the i-th perforation at time t. Integrating the fluid inflow rate of the i-th perforation at each time point within the first time period gives the total fluid inflow rate of the i-th perforation within the first time period.

[0077] Based on the energy ratio of each perforation, assuming that the energy injected into the wellbore at each time point is absorbed by the perforation, the energy ratio of each perforation at each time point can be used to represent the relative fluid injection volume of each perforation. Combined with the discharge volume at the wellhead at each time point, the fluid injection volume of each perforation is the integral of the product of the fracturing night discharge volume and the energy ratio of each perforation.

[0078] Assuming that the energy injected into the wellbore at each time point is absorbed by the perforations, the energy percentage of each perforation at each time point can represent the relative fluid injection volume of each perforation. Therefore, the fluid injection volume of each perforation is the integral of the fracturing night discharge volume and the energy percentage of each perforation.

[0079]

[0080] Where D(t) is the fracturing discharge rate at each time point; P i Let be the liquid inlet flow rate of the i-th perforation.

[0081] Taking a fractured well with a total of 6 perforations as an example, such as Figure 7 As shown, the following line graphs can be obtained: 301 for the fluid inlet flow rate of the first perforation, 302 for the second perforation, 303 for the third perforation, 304 for the fourth perforation, 305 for the fifth perforation, and 306 for the sixth perforation. Subsequently, by calculating the integral of the fluid inlet flow rate of each perforation over 11000 s, the fluid inlet flow rate of each perforation over 11000 s can be obtained, as shown in the following figures. Figure 8 As shown, the total liquid inflow of the first, second, third, fourth, fifth, and sixth perforations within 11000s can be obtained respectively. It can be seen that the liquid inflow of the sixth perforation is the largest, and the liquid inflow of the fifth perforation is the smallest.

[0082] In summary, the method provided in this embodiment, utilizing monitored DAS data and employing filtering and high-precision processing, can effectively extract the vibrations associated with sand injection and fluid introduction at perforations. Furthermore, it proposes characterizing the sand injection and fluid introduction intensity of each downhole perforation using energy percentage attributes, and combining this with the fracturing well's nighttime drainage rate, quantitatively calculating the sand injection and fluid introduction volume for each perforation, thereby achieving a quantitative evaluation of the reservoir stimulation effect.

[0083] The method provided in this embodiment utilizes the acoustic signals of DAS to calculate the amount of sand and fluid injected into each perforation during fracturing, providing key parameters for oil and gas field development. It effectively extracts downhole sand and fluid injection signals during fracturing; effectively improves the resolution and focusing of fluid injection signals from each perforation; and effectively enables quantitative calculation of sand and fluid injection into each perforation.

[0084] It should be noted that this application may display prompt interfaces, pop-ups, or output voice prompts before and during the collection of user data. These prompt interfaces, pop-ups, or voice prompts are used to inform the user that their data is being collected. This ensures that the application only begins the steps for collecting user data after receiving confirmation from the user regarding the prompt interface or pop-up; otherwise (i.e., without user confirmation), the steps for collecting user data end, meaning no user data is collected. In other words, all user data collected in this application is collected with the user's consent and authorization, and the collection, use, and processing of related user data must comply with the relevant laws, regulations, and standards of the relevant countries and regions.

[0085] It should be noted that the order of the method steps provided in the embodiments of this application can be appropriately adjusted, and the steps can also be added or removed as appropriate. Any method variations that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the protection scope of this application, and therefore will not be elaborated further.

[0086] Figure 9 This is a schematic diagram of the structure of a liquid inlet measuring device provided in an exemplary embodiment of this application.

[0087] The device includes:

[0088] The sensing module 501 is used to acquire sensing signals through a distributed optical fiber acoustic sensor (DAS) during fracturing operations; the sensing signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations installed at at least two fracturing depths, the perforations being used to pump fracturing fluid.

[0089] The calculation module 502 is used to calculate the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the sensing signal; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer;

[0090] The calculation module 502 is used to calculate the injection volume of the i-th perforation based on the fracturing fluid discharge rate of the fracturing well and the energy ratio; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fracturing well per unit time.

[0091] In an optional embodiment, the calculation module 502 is used to determine the signal in the target frequency band of the sensing signal as the target frequency band signal, wherein the noise interference of the sensing signal in the target frequency band is minimized;

[0092] The calculation module 502 is used to perform median filtering on the target frequency band signal to obtain a median filtered signal.

[0093] The calculation module 502 is used to calculate the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the median filtered signal.

[0094] In an optional embodiment, the calculation module 502 is used to divide the sensing signal into at least one frequency band corresponding to a frequency-divided signal.

[0095] The calculation module 502 is used to determine the frequency division signal with the least noise among the at least one frequency division signal as the target frequency band signal, wherein the target frequency band signal is the frequency division signal of the target frequency band.

[0096] In an optional embodiment, the calculation module 502 is used to traverse the target frequency band signal using a sliding window with a sliding step size, determine the energy value at the location of the sliding window as the median of all energy values ​​within the sliding window, and obtain the median filtered signal.

[0097] In an optional embodiment, the calculation module 502 is used to calculate the ratio of the energy value of the i-th aperture at time t to the total energy value at time t for time t in the median filtered signal and for the i-th aperture among the at least two apertures, to obtain the energy proportion of the i-th aperture at time t; t and i are positive integers;

[0098] Wherein, the i-th perforation corresponds to the i-th fracturing depth, and the energy value of the i-th perforation at time t is the energy value of time t and the i-th fracturing depth in the median filtered signal; the total energy value at time t is the sum of the energy values ​​of the at least two perforations at time t.

[0099] In one optional embodiment, the median filtered signal includes a first time period, the first time period including the time t;

[0100] The calculation module 502 is used to determine the fracturing fluid discharge rate at time t by multiplying the energy ratio of the i-th perforation at time t.

[0101] The calculation module 502 is used to calculate the sum of the liquid inflow at each moment of the i-th perforation within the first time period, so as to obtain the liquid inflow of the i-th perforation within the first time period.

[0102] It should be noted that the liquid inlet measurement device provided in the above embodiments is only an example of the division of the above functional modules. In actual applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the device can be divided into different functional modules to complete all or part of the functions described above. In addition, the liquid inlet measurement device and the liquid inlet measurement method embodiments provided in the above embodiments belong to the same concept, and the specific implementation process can be found in the method embodiments, which will not be repeated here.

[0103] Embodiments of this application also provide a computer device, comprising: a processor and a memory, wherein the memory stores at least one instruction, at least one program, code set, or instruction set, and the at least one instruction, at least one program, code set, or instruction set is loaded and executed by the processor to implement the liquid inlet measurement method provided in the above-described method embodiments. This computer device can be implemented as a DAS device.

[0104] For example, Figure 10 This is a schematic diagram of the structure of a computer device provided in an exemplary embodiment of this application.

[0105] Typically, computer device 1700 includes a processor 1701 and a memory 1702.

[0106] Processor 1701 may include one or more processing cores, such as a quad-core processor, an octa-core processor, etc. Processor 1701 may be implemented using at least one hardware form selected from DSP (Digital Signal Processing), FPGA (Field-Programmable Gate Array), and PLA (Programmable Logic Array). Processor 1701 may also include a main processor and a coprocessor. The main processor, also known as a CPU (Central Processing Unit), is used to process data in the wake-up state; the coprocessor is a low-power processor used to process data in the standby state. In some embodiments, processor 1701 may integrate a GPU (Graphics Processing Unit), which is responsible for rendering and drawing the content required to be displayed on the screen. In some embodiments, processor 1701 may also include an AI (Artificial Intelligence) processor, which is used to handle computational operations related to machine learning.

[0107] The memory 1702 may include one or more computer-readable storage media, which may be non-transitory. The memory 1702 may also include high-speed random access memory and non-volatile memory, such as one or more disk storage devices or flash memory devices. In some embodiments, the non-transitory computer-readable storage media in the memory 1702 is used to store at least one instruction, which is executed by the processor 1701 to implement the liquid inlet measurement method provided in the method embodiments of this application.

[0108] In some embodiments, the computer device 1700 may also optionally include a peripheral device interface 1703 and at least one peripheral device. The processor 1701, memory 1702, and peripheral device interface 1703 can be connected via a bus or signal line. Each peripheral device can be connected to the peripheral device interface 1703 via a bus, signal line, or circuit board. Specifically, the peripheral device includes at least one of the following: a radio frequency circuit 1704, a display screen 1705, a camera assembly 1706, an audio circuit 1707, and a power supply 1708.

[0109] Peripheral device interface 1703 can be used to connect at least one I / O (Input / Output) related peripheral device to processor 1701 and memory 1702. In some embodiments, processor 1701, memory 1702 and peripheral device interface 1703 are integrated on the same chip or circuit board; in some other embodiments, any one or two of processor 1701, memory 1702 and peripheral device interface 1703 can be implemented on separate chips or circuit boards, and this application embodiment is not limited in this respect.

[0110] The radio frequency (RF) circuit 1704 is used to receive and transmit RF (Radio Frequency) signals, also known as electromagnetic signals. The RF circuit 1704 communicates with communication networks and other communication devices via electromagnetic signals. The RF circuit 1704 converts electrical signals into electromagnetic signals for transmission, or converts received electromagnetic signals back into electrical signals. Optionally, the RF circuit 1704 includes: an antenna system, an RF transceiver, one or more amplifiers, a tuner, an oscillator, a digital signal processor, a codec chipset, a user identity module card, etc. The RF circuit 1704 can communicate with other computer devices via at least one wireless communication protocol. This wireless communication protocol includes, but is not limited to: the World Wide Web, metropolitan area networks, intranets, various generations of mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks, and / or WiFi (Wireless Fidelity) networks. In some embodiments, the RF circuit 1704 may also include circuitry related to NFC (Near Field Communication), which is not limited in this application.

[0111] Display screen 1705 is used to display a UI (User Interface). This UI may include graphics, text, icons, videos, and any combination thereof. When display screen 1705 is a touch display screen, it also has the ability to collect touch signals on or above its surface. These touch signals can be input as control signals to processor 1701 for processing. In this case, display screen 1705 can also be used to provide virtual buttons and / or a virtual keyboard, also known as soft buttons and / or a soft keyboard. In some embodiments, there may be one display screen 1705, positioned on the front panel of computer device 1700; in other embodiments, there may be at least two display screens 1705, respectively positioned on different surfaces of computer device 1700 or in a folded design; in still other embodiments, display screen 1705 may be a flexible display screen, positioned on a curved or folded surface of computer device 1700. Furthermore, display screen 1705 may also be configured as a non-rectangular, irregular shape, i.e., a non-rectangular screen. The display screen 1705 can be made of materials such as LCD (Liquid Crystal Display) and OLED (Organic Light-Emitting Diode).

[0112] The camera assembly 1706 is used to acquire images or videos. Optionally, the camera assembly 1706 includes a front-facing camera and a rear-facing camera. Typically, the front-facing camera is located on the front panel of the computer device 1700, and the rear-facing camera is located on the back of the computer device. In some embodiments, there are at least two rear-facing cameras, which are any one of a main camera, a depth-sensing camera, a wide-angle camera, and a telephoto camera, to achieve background blurring by fusion of the main camera and the depth-sensing camera, panoramic shooting by fusion of the main camera and the wide-angle camera, VR (Virtual Reality) shooting, or other fusion shooting functions. In some embodiments, the camera assembly 1706 may also include a flash. The flash can be a single-color temperature flash or a dual-color temperature flash. A dual-color temperature flash refers to a combination of a warm light flash and a cool light flash, which can be used for light compensation at different color temperatures.

[0113] The audio circuit 1707 may include a microphone and a speaker. The microphone is used to collect sound waves from the user and the environment, converting the sound waves into electrical signals that are input to the processor 1701 for processing, or input to the radio frequency circuit 1704 for voice communication. For stereo sound acquisition or noise reduction purposes, multiple microphones may be used, each located at a different part of the computer device 1700. The microphone may also be an array microphone or an omnidirectional microphone. The speaker is used to convert electrical signals from the processor 1701 or the radio frequency circuit 1704 into sound waves. The speaker may be a thin-film speaker as used in related technologies, or a piezoelectric ceramic speaker. When the speaker is a piezoelectric ceramic speaker, it can convert electrical signals not only into audible sound waves but also into inaudible sound waves for purposes such as distance measurement. In some embodiments, the audio circuit 1707 may also include a headphone jack.

[0114] Power supply 1708 is used to supply power to the various components in computer device 1700. Power supply 1708 can be AC ​​power, DC power, a disposable battery, or a rechargeable battery. When power supply 1708 includes a rechargeable battery, the rechargeable battery can be a wired rechargeable battery or a wireless rechargeable battery. A wired rechargeable battery is a battery that is charged via a wired line, and a wireless rechargeable battery is a battery that is charged via a wireless coil. The rechargeable battery can also be used to support fast charging technology.

[0115] In some embodiments, the computer device 1700 further includes one or more sensors 1709. The one or more sensors 1709 include, but are not limited to, an accelerometer 1710, a gyroscope 1711, a pressure sensor 1712, an optical sensor 1713, and a proximity sensor 1714.

[0116] Accelerometer 1710 can detect the magnitude of acceleration along the three coordinate axes of a coordinate system established by computer device 1700. For example, accelerometer 1710 can be used to detect the components of gravitational acceleration along the three coordinate axes. Processor 1701 can control touchscreen display 1705 to display the user interface in landscape or portrait view based on the gravitational acceleration signal acquired by accelerometer 1710. Accelerometer 1710 can also be used for games or for acquiring user motion data.

[0117] The gyroscope sensor 1711 can detect the orientation and rotation angle of the computer device 1700. The gyroscope sensor 1711 can work in conjunction with the accelerometer sensor 1710 to acquire 3D motion data from the user on the computer device 1700. Based on the data acquired by the gyroscope sensor 1711, the processor 1701 can perform the following functions: motion sensing (e.g., changing the UI based on the user's tilt), image stabilization during shooting, game control, and inertial navigation.

[0118] Pressure sensor 1712 can be disposed on the side bezel of computer device 1700 and / or on the lower layer of touch display screen 1705. When pressure sensor 1712 is disposed on the side bezel of computer device 1700, it can detect the user's grip signal on computer device 1700, and processor 1701 can perform left / right hand recognition or quick operation based on the grip signal collected by pressure sensor 1712. When pressure sensor 1712 is disposed on the lower layer of touch display screen 1705, processor 1701 can control operable controls on the UI interface based on the user's pressure operation on touch display screen 1705. Operable controls include at least one of button controls, scroll bar controls, icon controls, and menu controls.

[0119] Optical sensor 1713 is used to collect ambient light intensity. In one embodiment, processor 1701 can control the display brightness of touch display screen 1705 based on the ambient light intensity collected by optical sensor 1713. Specifically, when the ambient light intensity is high, the display brightness of touch display screen 1705 is increased; when the ambient light intensity is low, the display brightness of touch display screen 1705 is decreased. In another embodiment, processor 1701 can also dynamically adjust the shooting parameters of camera assembly 1706 based on the ambient light intensity collected by optical sensor 1713.

[0120] The proximity sensor 1714, also known as a distance sensor, is typically located on the front panel of the computer device 1700. The proximity sensor 1714 is used to detect the distance between the user and the front of the computer device 1700. In one embodiment, when the proximity sensor 1714 detects that the distance between the user and the front of the computer device 1700 is gradually decreasing, the processor 1701 controls the touch display screen 1705 to switch from a screen-on state to a screen-off state; when the proximity sensor 1714 detects that the distance between the user and the front of the computer device 1700 is gradually increasing, the processor 1701 controls the touch display screen 1705 to switch from a screen-off state to a screen-on state.

[0121] Those skilled in the art will understand that Figure 10 The structure shown does not constitute a limitation on the computer device 1700, and may include more or fewer components than shown, or combine certain components, or use different component arrangements.

[0122] This application also provides a computer-readable storage medium storing at least one instruction, at least one program, code set, or instruction set. When the at least one instruction, at least one program, code set, or instruction set is loaded and executed by the processor of a computer device, the liquid inlet measurement method provided in the above-described method embodiments is implemented.

[0123] This application also provides a computer program product or computer program including computer instructions stored in a computer-readable storage medium. A processor of a computer device reads the computer instructions from the computer-readable storage medium and executes the computer instructions, causing the computer device to perform the liquid inlet measurement method provided in the above-described method embodiments.

[0124] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a read-only memory, a disk, or an optical disk.

[0125] The above description is merely an optional embodiment of this application and is not intended to limit this application. Any modifications, equivalent switching, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application.

Claims

1. A method of measuring the amount of liquid introduced, characterized by, The method includes: During fracturing operations, sensing signals are acquired by a distributed optical fiber acoustic sensor (DAS); the sensing signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations at at least two fracturing depths, the perforations being used to pump fracturing fluid; Based on the sensing signal, the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations is calculated; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer; Based on the fracturing fluid discharge rate of the fractured well and the energy ratio, the fluid injection rate of the i-th perforation is calculated; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fractured well per unit time.

2. The method of claim 1, wherein, The step of calculating the energy percentage of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the sensing signal includes: The signal in the target frequency band of the sensing signal is determined as the target frequency band signal, and the noise interference of the sensing signal in the target frequency band is minimized. The target frequency band signal is subjected to median filtering to obtain a median filtered signal; Based on the median filtered signal, calculate the energy percentage of the acoustic signal corresponding to the i-th perforation among the at least two perforations.

3. The method of claim 2, wherein, The step of determining the target frequency band signal in the sensing signal as the target frequency band signal includes: The sensing signal is divided into at least one frequency band corresponding to the frequency division signal; The frequency division signal with the least noise among the at least one frequency division signal is determined as the target frequency band signal, and the target frequency band signal is the frequency division signal of the target frequency band.

4. The method of claim 2, wherein, The process of performing median filtering on the target frequency band signal to obtain a median filtered signal includes: The target frequency band signal is traversed using a sliding window with a sliding step size. The energy value at the location of the sliding window is determined as the median of all energy values ​​within the sliding window, thus obtaining the median filtered signal.

5. The method of claim 2, wherein, The step of calculating the energy proportion of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the median filtered signal includes: For time t in the median filtered signal and the i-th aperture among the at least two apertures, calculate the ratio of the energy value of the i-th aperture at time t to the total energy value at time t, and obtain the energy proportion of the i-th aperture at time t; t and i are positive integers; Wherein, the i-th perforation corresponds to the i-th fracturing depth, and the energy value of the i-th perforation at time t is the energy value of time t and the i-th fracturing depth in the median filtered signal; the total energy value at time t is the sum of the energy values ​​of the at least two perforations at time t.

6. The method of claim 5, wherein, The median filtered signal includes a first time period, which includes the time t. The calculation of the fluid injection rate for the i-th perforation based on the fracturing fluid discharge rate and the energy ratio of the fracturing well includes: The product of the fracturing fluid discharge rate at time t and the energy percentage of the i-th perforation at time t is determined as the fluid inflow rate of the i-th perforation at time t. The sum of the liquid inflow at each moment of the i-th perforation within the first time period is calculated to obtain the liquid inflow of the i-th perforation within the first time period.

7. A device for measuring liquid inflow, characterized in that, The device includes: A sensing module is used to acquire sensing signals through a distributed optical fiber acoustic sensor (DAS) during fracturing operations; the sensing signals include acoustic signals measured at different fracturing depths; the DAS is installed inside the fracturing well; the fracturing well includes at least two perforations at at least two fracturing depths, the perforations being used to pump fracturing fluid; The calculation module is used to calculate the energy ratio of the acoustic signal corresponding to the i-th perforation among the at least two perforations based on the sensing signal; the energy ratio is the ratio of the energy value of the acoustic signal corresponding to the i-th perforation to the total energy value, and the total energy value is the sum of the energy values ​​of the acoustic signals corresponding to the at least two perforations; the energy ratio is used to indicate the liquid inflow ratio of the i-th perforation, where i is an integer; The calculation module is used to calculate the injection volume of the i-th perforation based on the fracturing fluid discharge rate of the fracturing well and the energy ratio; the fracturing fluid discharge rate is the amount of fracturing fluid injected into the fracturing well per unit time.

8. A computer device, characterized in that, The computer device includes a processor and a memory, the memory storing at least one program, which is loaded and executed by the processor to implement the liquid inlet measurement method as described in any one of claims 1 to 7.

9. A computer-readable storage medium, characterized in that, The readable storage medium stores at least one program, which is loaded and executed by a processor to implement the liquid inlet measurement method as described in any one of claims 1 to 7.

10. A computer program product, characterised in that, The computer program product includes computer instructions stored in a computer-readable storage medium, a processor of a computer device reading the computer instructions from the computer-readable storage medium, and the processor executing the computer instructions to cause the computer device to perform the liquid inlet measurement method as described in any one of claims 1 to 7.

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