Method, system and device for measuring working fluid level of oil well based on infrasonic waves

Abstract

The invention discloses an oil well working fluid level measuring method, system and device based on infrasonic waves. The method comprises the following steps: acquiring an acquired mixed infrasonic wave pulse signal, and separating a tubing coupling reflection wave curve and an oil well liquid level reflection wave curve from the mixed infrasonic wave pulse signal; a gradient descent algorithm is adopted to find a multi-section waveform minimum value point on the tubing coupling reflection wave curve, and the propagation speed of the infrasonic wave pulse in the oil sleeve annulus is determined according to the sampling point time corresponding to the minimum value point and the length of the tubing coupling; based on the selected depth base point, reversely searching a first minimum value point on the oil well liquid level reflection wave curve by adopting a gradient descent algorithm, and determining the reflection time of the infrasonic wave pulse according to the sampling point time corresponding to the searched minimum value point; and the depth of the working fluid level of the oil well is determined according to the propagation speed of the infrasonic wave pulse in the oil sleeve annulus and the reflection time of the infrasonic wave pulse. The measuring efficiency, the measuring precision and the real-time performance of the working fluid level of the oil well can be improved.

Description

Technical Field

[0001] This invention relates to the field of oil well dynamic fluid level measurement technology, and in particular to a method, system and device for measuring oil well dynamic fluid level based on infrasound. Background Technology

[0002] In oil extraction, the dynamic fluid level depth of an oil well is a crucial parameter for monitoring downhole conditions. The dynamic fluid level directly reflects important parameters for evaluating and optimizing oil production processes, such as reservoir fluid supply capacity, downhole supply and drainage coordination, and the submersion of the pumping unit. With the advancement of digital transformation in oilfields, real-time and accurate measurement of downhole dynamic fluid level data is necessary to conduct multi-parameter coordinated adjustments to oil production processes, thereby establishing a rational extraction system, improving production efficiency, reducing energy consumption, and maximizing the economic benefits of oil extraction.

[0003] Traditional oil well dynamic fluid level measurement involves installing instruments at the wellhead and manually operating a casing gas or nitrogen cylinder generator to produce acoustic pulses. The acoustic waves propagate within the annular space of the tubing and casing, generating reflected pulse waves upon encountering echo markers, tubing couplings, and the fluid surface. The propagation speed of the acoustic pulses within the annular space of the tubing and casing is manually calculated and indirectly measured using the position of the echo markers or the spacing of the couplings. Then, the distance between the oil well fluid surface and the wellhead is manually calculated based on the reflection time of the reflected pulse waves generated by the fluid surface and the indirectly measured propagation speed of the acoustic pulses.

[0004] In recent years, with the development of dynamic fluid level soft measurement technology, intelligent algorithms for dynamic fluid level soft measurement have begun to emerge. The mainstream algorithm is to calculate the pump dynamometer by solving the wave equation based on the surface dynamometer diagram, rod and pump parameters, and then use the pump dynamometer diagram to establish a dynamic fluid level calculation model to obtain the dynamic fluid level of the oil well. Summary of the Invention

[0005] The inventors of this application have discovered that traditional oil well dynamic fluid level measurement requires manual control of a casing gas or nitrogen cylinder generator to send infrasonic pulses into the annulus. Furthermore, the extraction of characteristic locations such as the wellhead position, the start and end points of the tubing coupling wave, and the fluid level, as well as the calculation of the propagation speed of the acoustic pulses in the annulus and the dynamic fluid level depth, are all manually measured and calculated by technicians. This process is time-consuming and suffers from drawbacks such as poor real-time performance, large errors, and low efficiency. Existing intelligent algorithms for soft dynamic fluid level measurement involve complex calculation processes, and with adjustments to production processes and changes in downhole conditions, parameters such as damping coefficients and boundary conditions during the soft measurement process are difficult to confirm, leading to a decrease in the accuracy of the calculation model's predictions.

[0006] In view of the above problems, the present invention is proposed to provide a method, system and apparatus for measuring the dynamic fluid level in oil wells based on infrasound, which overcomes or at least partially solves the above problems.

[0007] In a first aspect, embodiments of the present invention provide a method for measuring the dynamic fluid level in oil wells based on infrasound, comprising:

[0008] Acquire the mixed infrasound pulse signal collected by the infrasound receiving device. The mixed infrasound pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends an infrasound pulse into the annulus of the casing.

[0009] The tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve are separated from the mixed infrasonic pulse signal;

[0010] The first-order gradient descent algorithm is used to find multiple waveform minima on the reflected wave curve of the tubing coupling. Based on the sampling time corresponding to the multiple minima and the length of the tubing coupling, the propagation speed of the infrasound pulse in the tubing annulus is determined.

[0011] Based on the selected depth reference point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then return.

[0012] The depth of the dynamic fluid level in the oil well is determined based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

[0013] In some optional embodiments, acquiring the mixed infrasound pulse signal collected by the infrasound receiving device includes:

[0014] Control the infrasound generator to send infrasound pulses into the annulus of the oil casing;

[0015] The infrasound receiving device is controlled to receive the mixed infrasound pulse signal reflected back by the oil pipe coupling and the liquid surface;

[0016] Acquire the mixed infrasound pulse signal received by the infrasound receiving device.

[0017] In some optional embodiments, separating the tubing coupling reflection wave curve and the well fluid surface reflection wave curve from the mixed infrasonic pulse signal includes:

[0018] The mixed infrasonic pulse signal is subjected to noise reduction, amplification and filtering to obtain the separated infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface;

[0019] The infrasonic pulse signals reflected by the separated tubing coupling and the infrasonic pulse signals reflected by the oil well fluid surface are processed by analog-to-digital conversion to obtain the reflection wave curves of the tubing coupling and the oil well fluid surface.

[0020] In some optional embodiments, the analog-to-digital conversion processing of the separated tubing coupling reflected infrasonic pulse signal and the oil well fluid surface reflected infrasonic pulse signal to obtain the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve includes:

[0021] The analog-to-digital conversion unit samples the infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface at a specific sampling frequency. During the sampling process, the pulse signal value at the sampling point is processed by analog-to-digital conversion to obtain the corresponding digital signal value. Based on the digital signal value at the sampling point, the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve are formed.

[0022] In some optional embodiments, the step of using a gradient descent algorithm to find multiple waveform minima on the reflected wave curve of the tubing coupling, and determining the propagation speed of the infrasonic pulse in the annulus based on the sampling time corresponding to the multiple minima and the length of the tubing coupling, includes:

[0023] From the reflected wave curves of the tubing coupling, select the reflected wave curve of the tubing coupling with a stable front end, select a current sampling point n-1, and use a first-order descent algorithm to calculate the time axis coordinate of the next sampling point n:

[0024]

[0025] Where: X n Let X be the time axis coordinate of the nth sampling point of the reflected wave curve of the oil pipe coupling. n-1 The time axis coordinate of the (n-1)th sampling point of the reflected wave curve of the oil pipe coupling; a is a constant;

[0026] The derivative of the signal value at the (n-1)th sampling point of the reflected wave curve of the tubing coupling:

[0027]

[0028] Where, f(X) n-1 f(X) represents the signal value at the (n-1)th sampling point. n-2 ) represents the signal value at the (n-2)th sampling point;

[0029] Based on the calculated time axis coordinates of sampling point n, the signal value of sampling point n is determined. If the signal value of sampling point n is less than the signal value of sampling point n-1, sampling point n is taken as the current sampling point, and the process continues to execute the step of calculating the time axis coordinates of the next sampling point using the first-order step descent algorithm, until the signal value of the next sampling point is greater than the signal value of the current sampling point. Then the current sampling point is a local minimum point.

[0030] Repeat the above process of determining a minimum point multiple times until the minimum point of multiple stable waveforms in the tubing coupling reflection wave curve is found; determine the propagation speed of the infrasonic pulse in the tubing annulus based on the minimum point of the multiple stable waveforms.

[0031] In some optional embodiments, determining the propagation speed of the infrasonic pulse in the annulus based on the minimum points of the multiple waveform segments includes:

[0032] From a series of consecutive minimum points of waveforms, select g minimum points. Mark N as the time axis coordinate of the sampling point corresponding to the minimum point of the first coupling wave reflection curve, and mark M as the time axis coordinate of the sampling point of the minimum point of the g-th coupling wave reflection curve. Then, the time it takes for the infrasound reflected wave to pass through g consecutive oil pipe couplings can be calculated as follows:

[0033] t1 = (MN)·T,

[0034] Where: T is the sampling time interval, then f is the sampling frequency of the analog-to-digital conversion unit for the infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface;

[0035] Therefore, the propagation speed of infrasound in the annulus is: Where L is the average length of the downhole tubing coupling.

[0036] In some optional embodiments, based on a selected depth reference point, a gradient descent algorithm is used to reverse-engineer the first minimum point on the oil well fluid surface reflection wave curve. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to return after being reflected by the oil well fluid surface, including:

[0037] Based on the time axis coordinates of the reference point corresponding to the selected depth reference point on the reflected wave curve, the minimum point is found by reverse searching using the first-order gradient descent algorithm, and the time axis coordinates of the sampling point corresponding to the minimum point are marked as Y.

[0038] Based on the sampling time corresponding to the first local minimum point found, the reflection time t2 of the infrasound pulse is determined using the following formula.

[0039] In some optional embodiments, determining the depth of the dynamic fluid level in the oil well based on the propagation velocity and reflection time of the infrasonic pulse within the annulus includes:

[0040] Based on the propagation velocity v of the infrasonic pulse in the annulus and the reflection time t2 of the infrasonic pulse, the depth of the dynamic fluid level in the oil well is determined using the following formula:

[0041]

[0042] Secondly, embodiments of the present invention provide an oil well dynamic fluid level measuring device based on infrasound, comprising:

[0043] The infrasound acquisition unit is used to acquire the mixed infrasound pulse signal collected by the infrasound receiving device. The mixed infrasound pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends the infrasound pulse into the annulus.

[0044] The infrasound signal processing unit is used to separate the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasound pulse signal.

[0045] The control processing unit is used to find multiple waveform minima on the reflected wave curve of the tubing coupling using a gradient descent algorithm, and to determine the propagation speed of the infrasound pulse in the tubing annulus based on the sampling time corresponding to the multiple minima and the length of the tubing coupling.

[0046] Based on the selected depth reference point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse, which is the downhole fluid surface wave reflection point. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then returning.

[0047] The depth of the dynamic fluid level in the oil well is determined based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

[0048] This invention also provides an infrasound-based oil well dynamic fluid level measurement system, characterized in that it includes: an infrasound generator, an infrasound receiver, and the infrasound-based oil well dynamic fluid level measurement device described above.

[0049] Infrasound generator, used to send infrasound pulses into the annulus of the oil casing;

[0050] The infrasound receiving device is used to collect the mixed infrasound pulse signal that is reflected back by the tubing coupling and the oil well fluid surface after the infrasound pulse is sent into the annulus by the infrasound generator.

[0051] The infrasound-based oil well dynamic fluid level measurement device is used to control the operation of the infrasound generator and the infrasound receiver, and to determine the depth of the oil well dynamic fluid level based on the mixed infrasound pulse signal collected by the infrasound receiver.

[0052] This invention also provides a computer storage medium storing computer-executable instructions, which, when executed by a processor, implement the above-described infrasound-based method for measuring the dynamic fluid level in oil wells.

[0053] This invention also provides a terminal device, including: a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the above-described infrasound-based method for measuring the dynamic fluid level in oil wells.

[0054] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0055] The infrasound-based method for measuring dynamic fluid level in oil wells provided in this invention separates the tubing coupling reflection wave curve and the oil well fluid level reflection wave curve from the mixed infrasound pulse signal acquired by the infrasound receiving device. Based on the separated tubing coupling reflection wave curve, a gradient descent algorithm is used to determine the propagation speed of the infrasound pulse in the annulus. Based on the separated oil well fluid level reflection wave curve, the reflection time of the infrasound pulse is determined. The depth of the dynamic fluid level in the oil well is determined by the propagation speed and reflection time of the infrasound pulse in the annulus. This method replaces traditional manual measurement, improving the measurement efficiency and real-time performance of dynamic fluid level, and providing technical support for multi-parameter linkage adjustment and intelligent control of oil production processes. Furthermore, from an algorithmic perspective, it avoids the complex algorithm of solving the wave equation through surface dynamometer maps to calculate the dynamic fluid level, solving the problem of inaccurate dynamic fluid level prediction due to inaccurate parameter data acquisition in the algorithm model, thus improving the measurement accuracy of the dynamic fluid level. Experiments have confirmed that the measurement error using this method is within ±10m.

[0056] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0057] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0058] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0059] Figure 1 This is a flowchart of the method for measuring the dynamic fluid level in an oil well based on acoustic wave measurement in Embodiment 1 of the present invention;

[0060] Figure 2 This is a flowchart of the method for measuring the dynamic fluid level in an oil well based on acoustic wave measurement in Embodiment 2 of the present invention;

[0061] Figure 3 This is a schematic diagram of the internal integrated module of the oil well dynamic fluid level measuring device in Embodiment 2 of the present invention;

[0062] Figure 4 This is one of the reflection wave curves of the tubing coupling and the oil well fluid surface in the embodiments of the present invention;

[0063] Figure 5 This is a schematic diagram illustrating the implementation principle of the first-order descent algorithm in an embodiment of the present invention.

[0064] Figure 6 This is the second example of the reflected wave curves of the tubing coupling and the oil well fluid surface in this embodiment of the invention;

[0065] Figure 7 This is a schematic diagram of the structure of the oil well dynamic fluid level measuring device based on acoustic wave measurement in an embodiment of the present invention;

[0066] Figure 8 This is a schematic diagram of the structure of the oil well dynamic fluid level measurement system based on acoustic wave measurement in an embodiment of the present invention. Detailed Implementation

[0067] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0068] To address the problems of poor real-time performance, large errors, and low efficiency in traditional oil well dynamic fluid level measurement and calculation methods, as well as the decreased prediction accuracy of intelligent algorithms used for soft dynamic fluid level measurement, this invention provides an infrasound-based oil well dynamic fluid level measurement method. This method uses a first-order gradient descent algorithm to determine the propagation velocity and reflection time of the infrasound pulse within the annulus, thereby determining the depth of the oil well dynamic fluid level. This method completely replaces traditional manual measurement, improving the efficiency and real-time performance of oil well dynamic fluid level data acquisition. Furthermore, it avoids the complex algorithm of solving the wave equation using surface dynamometer maps to calculate the dynamic fluid level, and the use of the first-order gradient descent algorithm improves the measurement accuracy of the dynamic fluid level.

[0069] Example 1

[0070] Embodiment 1 of the present invention provides a method for measuring the dynamic fluid level in oil wells based on infrasound, the process of which is as follows: Figure 1 As shown, it includes the following steps:

[0071] Step S101: Acquire the mixed infrasound pulse signal collected by the infrasound receiving device.

[0072] The mixed infrasonic pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasonic generator sends an infrasonic pulse into the annulus.

[0073] When oil well dynamic fluid level measurement is required, the control processing unit can control an infrasound generator to send infrasound pulses into the annulus (the space between the tubing and casing). The infrasound pulses propagate downhole within the annulus. If they encounter an object during propagation, the infrasound signal is reflected back towards the wellhead. These infrasound signals can be collected by an infrasound receiver. During propagation downhole, more than one object may be encountered; therefore, the infrasound receiver collects a mixed infrasound pulse signal. The control processing unit then obtains the collected mixed infrasound pulse signal from the infrasound receiver.

[0074] Step S102: Separate the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasonic pulse signal.

[0075] The acquired mixed infrasonic pulse signal may include infrasonic signals emitted back by various objects downhole. The desired signal can be separated from the mixed infrasonic pulse signal. For example, in the dynamic fluid level measurement in this application, it is necessary to separate the infrasonic waves reflected by the tubing coupling and the infrasonic waves reflected by the oil well fluid level, that is, to separate the tubing coupling reflection wave curve and the oil well fluid level reflection wave curve.

[0076] Step S103: Use the gradient descent algorithm to find multiple waveform minima on the tubing coupling reflection wave curve. Based on the sampling time corresponding to the multiple minima and the length of the tubing coupling, determine the propagation speed of the infrasound pulse in the tubing annulus.

[0077] Since the tubing coupling may have multiple segments, there may be multiple minimum points on the separated tubing coupling reflection wave curve. Corresponding to the multiple tubing coupling segments, and since the length of the tubing coupling is available, by finding the corresponding point on the reflected infrasound wave curve for each tubing coupling segment, the reflection time of different tubing coupling segments can be obtained. Based on these reflection times and the length of the tubing coupling, the propagation speed of infrasound in the annulus can be determined.

[0078] Step S104: Based on the selected depth base point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the first minimum point found. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then return.

[0079] In this step, the control processing unit uses the gradient descent algorithm to process the infrasonic pulse signal reflected by the liquid surface. Based on the selected bottom liquid surface reflection wave sampling reference point, it reverses to find the corresponding sampling point where the bottom liquid surface reflection wave arrives, and obtains the arrival time of the liquid surface reflection wave.

[0080] A base point can be selected as the reference point, and the first minimum point on the oil well fluid surface reflection wave curve can be found by reverse searching. The selected depth should be greater than the pump hanger depth, which is the depth from the wellhead to the pump. This allows us to find the reflection point of the downhole fluid surface on the oil well fluid surface reflection wave curve. Optionally, the pump hanger depth can be used as the base point, or the depth of other reference objects can be chosen. Based on the reference point corresponding to the pump hanger depth on the bottom hole fluid surface reflection wave curve, the reflection point of the downhole fluid surface is found on the bottom hole fluid surface reflection wave curve. The reflection time taken for the infrasonic pulse to travel from emission to return after being reflected by the oil well fluid surface is determined by the coordinates of the sampling point corresponding to this point and the sampling frequency of the infrasonic pulse signal reflected from the oil well fluid surface.

[0081] The reflection point of the downhole fluid surface on the oil well fluid surface reflection wave curve can be determined by using a first-order gradient descent algorithm based on a selected depth base point to find the first minimum point on the oil well fluid surface reflection wave curve. The reflection time of the infrasonic pulse can be determined based on the sampling time corresponding to the found minimum point.

[0082] Step S105: Determine the depth of the dynamic fluid level in the oil well based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

[0083] The time taken for an infrasonic pulse to travel from emission to contact with the fluid surface can be determined based on the reflection time of the infrasonic pulse. Then, the depth of the dynamic fluid surface in the oil well can be determined based on the propagation speed of the infrasonic pulse in the annulus and the time taken for the infrasonic pulse to travel from emission to contact with the fluid surface.

[0084] The infrasound-based oil well dynamic fluid level measurement method provided in this invention introduces a continuously programmable infrasound generator into the traditional dynamic fluid level measurement device. A control processing unit controls the operation of the infrasound generator and receiver, eliminating the need for manual operation. It can autonomously and continuously generate and acquire transmitted infrasound pulses within the annular space of the tubing and casing. Furthermore, the control processing unit utilizes a gradient descent algorithm to accurately identify reflected infrasound pulses and calculate the dynamic fluid level in real time. This allows for automatic and accurate identification of tubing couplings and fluid surface reflected infrasound pulses, and automatic calculation of the oil well dynamic fluid level.

[0085] Example 2

[0086] This invention provides a specific implementation flow of the above-described infrasound-based oil well dynamic fluid level measurement method, see [link to implementation details]. Figure 2As shown, the schematic diagram of the internal integrated module for measurement based on the oil well dynamic fluid level measuring device is as follows. Figure 3 As shown, it includes the following steps:

[0087] Step S201: Control the infrasound generator to send infrasound pulses into the annulus of the oil jacket.

[0088] The infrasound generator is a programmable infrasound generator. The control and processing unit controls the infrasound generator to send infrasound pulses into the annulus. The infrasound pulse signal propagates downhole within the annulus and is reflected back when it encounters an object. The annulus is the ring-shaped space between the tubing and casing.

[0089] Step S202: Control the infrasound receiving device to receive the mixed infrasound pulse signal reflected back by the oil pipe coupling and the liquid surface.

[0090] As infrasound propagates downhole, it encounters multiple tubing couplings and bottom fluid surfaces. Upon contact with these surfaces, the infrasound waves are reflected back towards the wellhead. The infrasound receiving device receives the mixed infrasound pulse signal reflected back from the tubing couplings and fluid surfaces at the casing inlet.

[0091] Step S203: The control processing unit acquires the mixed infrasound pulse signal received by the infrasound receiving device.

[0092] The above steps S201-203 achieve the acquisition of the mixed infrasound pulse signal collected by the infrasound receiving device.

[0093] Step S204: The mixed infrasonic pulse signal is denoised, amplified and filtered to obtain the separated infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface.

[0094] In this step, noise reduction, amplification, and filtering can be selectively applied to the signal to improve signal quality and reduce noise. Since the acquired mixed infrasonic pulse signal may contain multiple noise sources, noise reduction processing can be performed. To make the signal characteristics more apparent, the mixed infrasonic pulse signal can be amplified, and the signal can also be filtered to remove clutter. The infrasonic pulse signal reflected from the tubing coupling and the infrasonic pulse signal reflected from the oil well fluid surface are separated from the processed signal; the separated signal is usually an analog signal.

[0095] Step S205: Perform analog-to-digital conversion on the separated infrasonic pulse signals reflected by the tubing coupling and the infrasonic pulse signals reflected by the oil well fluid surface to obtain the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve.

[0096] The analog-to-digital conversion unit samples the infrasonic pulse signals reflected from the tubing coupling and the infrasonic pulse signals reflected from the oil well fluid surface at specific sampling frequencies. During the sampling process, the pulse signal values ​​at the sampling points are processed by analog-to-digital conversion to obtain the corresponding digital signal values. Based on the digital signal values ​​at the sampling points, the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve are formed. (See [link]). Figure 4 The two curves shown can be used to select the sampling frequency as needed, for example, f = 1kHz or 2kHz, etc.

[0097] The above steps S204-205 achieve the separation of the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasonic pulse signal.

[0098] Step S206: Use the gradient descent algorithm to find multiple waveform minima on the tubing coupling reflection wave curve. Based on the sampling time corresponding to the multiple minima and the length of the tubing coupling, determine the propagation speed of the infrasound pulse in the tubing annulus.

[0099] After separating the reflected wave curves of the tubing couplings, the reflection point corresponding to each tubing coupling on the curve can be found by searching for the minimum point. The control processing unit can use the gradient descent algorithm to process the infrasonic pulse signal reflected by the tubing couplings, and find the minimum points of multiple consecutive waveform segments on the curve, which are the reflection points corresponding to each tubing coupling. The gradient descent algorithm can be a first-order gradient descent algorithm.

[0100] from Figure 4 As shown in the tubing coupling reflection wave curve, the front end of the curve is a curve with a relatively stable amplitude and a relatively large amplitude, while the rear end has a very small amplitude. The tubing coupling reflection wave curve with a stable front end is selected, and a sampling point is randomly selected from the selected tubing coupling reflection wave curve as the base point. The selected base point is used as the starting point of the first-order descent algorithm. Starting from the starting point, the first-order descent algorithm is used to determine the minimum points of multiple waveforms on the tubing coupling reflection wave curve. The number of waveform segments that need to determine the minimum points cannot exceed the number of stable waveform segments. Each waveform segment has one minimum point.

[0101] The implementation principle of the first-order gradient descent algorithm is as follows: Figure 5 As shown, the specific implementation steps based on this algorithm are as follows:

[0102] 1) Select a stable tubing coupling reflection wave curve from the tubing coupling reflection wave curve, choose a current sampling point n-1, and use a first-order descent algorithm to calculate the time axis coordinate of the next sampling point n:

[0103]

[0104] Where: X nX represents the time axis coordinate of the nth sampling point of the reflected wave curve of the oil pipe coupling. n-1 The time axis coordinates of the (n-1)th sampling point of the reflected wave curve of the oil pipe coupling;

[0105] 'a' is a constant representing the step size, which is the distance between the current sampling point n-1 and the next sampling point n. The value of 'a' can be set and can be input into the control processing unit of the oil well dynamic fluid level measurement device through the human-machine interface; for example, 'a' can be the amplification factor of the reflected infrasound signal.

[0106] The derivative of the signal value at the (n-1)th sampling point of the reflected wave curve of the tubing coupling is calculated using the following formula:

[0107]

[0108] Where, f(X) n-1 f(X) represents the signal value at the (n-1)th sampling point. n-2 ) represents the signal value at the (n-2)th sampling point;

[0109] Based on the calculated time axis coordinates of sampling point n, the signal value of sampling point n is determined. If the signal value of sampling point n is less than the signal value of sampling point n-1, that is... If the value is less than 0, take sampling point n as the current sampling point and return to continue executing the step of calculating the time axis coordinate of the next sampling point using the first-order step descent algorithm, until the signal value of the next sampling point is greater than the signal value of the current sampling point. If the value is greater than 0, the algorithm ends and the minimum point is obtained;

[0110] 2) By performing the process described in 1), a minimum point can be found in the reflection wave curve of the tubing coupling. By performing the process described in 1) multiple times, multiple minimum points can be obtained on the reflection wave curve of the tubing coupling. That is, the process of determining a minimum point is repeated multiple times until the minimum points of multiple waveforms in the selected stable part of the front end of the tubing coupling reflection wave curve are found. The number of times the process of determining a minimum point is repeated is equal to the number of waveform segments for which the minimum points need to be determined.

[0111] 3) Determine the propagation speed of the infrasonic pulse in the annulus based on the minimum points of multiple waveform segments. The steps are as follows:

[0112] From a series of consecutive minimum points of waveforms, select g minimum points. Mark N as the time axis coordinate of the sampling point corresponding to the minimum point of the first coupling wave reflection curve, and mark M as the time axis coordinate of the sampling point of the minimum point of the g-th coupling wave reflection curve. Then, the time t1 for the infrasound reflected wave to pass through g consecutive oil pipe couplings can be calculated.

[0113] t1 = (MN)·T,

[0114] Where: T is the sampling time interval, then The frequency f is the sampling frequency of the analog-to-digital conversion unit for the infrasonic pulse signals reflected from the tubing coupling and the infrasonic pulse signals reflected from the oil well fluid surface; therefore

[0115] Therefore, the propagation speed of infrasound in the annulus is: Where L is the average length of the downhole tubing coupling, which can be obtained from the basic parameters of the oil well and input into the control and processing unit of the oil well dynamic fluid level measurement device through the human-machine interface.

[0116] Step S207: Based on the selected depth base point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse. The infrasonic pulse reflection time of the oil well fluid surface is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then return.

[0117] The pump hanger depth can be used as the depth reference point. Since the oil pump is generally below the liquid surface, the search can be performed in reverse on the oil well liquid surface reflection wave curve. The reflection point on the curve after the downhole liquid surface reflects the infrasonic wave can be found based on the pump hanger depth. The reflection time of the infrasonic wave pulse on the oil well liquid surface can be determined based on the reflection point.

[0118] After obtaining the propagation speed of sound waves in the annulus through the above calculation, the depth reference point can be calculated based on the propagation speed and the pump hanger depth. For example, the propagation speed of infrasound in the annulus is between 220 and 400 (m / s). With the pump hanger depth L, the depth reference point selected on the oil well fluid surface reflection wave curve for calculating the fluid surface reflection wave sampling is: 2Lf / 220.

[0119] It is possible to use a first-order gradient descent algorithm based on the pump mounting depth K from... Figure 6 The first minimum point was found by reverse-engineering the oil well fluid surface reflection wave curve. The reflection time of the infrasonic pulse was determined based on the sampling time corresponding to the found minimum point. The specific process is as follows:

[0120] 1) Based on the time axis coordinates of the reference point corresponding to the selected depth reference point on the reflection wave curve, the minimum point is found by using the first-order gradient descent algorithm. The time axis coordinates of the sampling point corresponding to the first minimum point are marked as Y.

[0121] Using the pump hanger depth K as the base point, the time axis coordinate X of the base point B of the oil well fluid surface reflection wave curve is determined based on the pump hanger depth K. b =2K / (vT)=2Kf / v, and starting from this base point, the first minimum point is found by using the first-order gradient descent algorithm.

[0122] 2) Based on the sampling time corresponding to the first minimum point found, the reflection time t2 of the infrasound pulse is determined using the following formula:

[0123] Step S208: Determine the depth of the dynamic fluid level in the oil well based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

[0124] The reflection time is the time it takes for an infrasound wave to travel from its emission to its return after being reflected by the oil well fluid surface. Therefore, the time it takes for an infrasound wave to travel from its emission to encountering the oil well fluid surface is...

[0125] Based on the propagation velocity v of the infrasonic pulse in the annulus and the reflection time t2 of the infrasonic pulse, the depth of the dynamic fluid level in the oil well is determined using the following formula:

[0126]

[0127] The infrasound-based dynamic fluid level measurement method for oil wells provided in this invention enables continuous, automatic, and high-precision measurement of the dynamic fluid level. This method can continuously measure the dynamic fluid level under any oil well operating conditions, with a measurement depth range of 200–3000 m and a minimum measurement interval of 3 minutes. The method employs a program-controlled infrasound generator, replacing traditional casing gas or nitrogen cylinder acoustic generators. The integrated design of the measuring device, installed at the wellhead, enables autonomous dynamic fluid level measurement, completely replacing traditional manual measurement. This improves the real-time performance of dynamic fluid level data acquisition and the measurement efficiency, providing technical support for multi-parameter linkage adjustment and intelligent control in oil production processes. From an algorithmic perspective, it avoids the complex algorithm of solving the wave equation through surface dynamometer maps to calculate the dynamic fluid level, solving the problem of inaccurate dynamic fluid level prediction due to inaccurate parameter data acquisition in the algorithm model, thus improving the measurement accuracy. Experiments have confirmed that the measurement error is within ±10 m.

[0128] Based on the same inventive concept, this invention also provides an infrasound-based oil well dynamic fluid level measurement device. This device can be installed in a computer device with data processing capabilities. The structure of the device is as follows: Figure 7 As shown, it includes: an infrasound acquisition unit 101, an infrasound signal processing unit 102, and a control processing unit 103.

[0129] Infrasound acquisition unit 101 is used to acquire the mixed infrasound pulse signal collected by the infrasound receiving device. The mixed infrasound pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends the infrasound pulse into the annulus.

[0130] The infrasound signal processing unit 102 is used to separate the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasound pulse signal.

[0131] The control processing unit 103 is used to find multiple waveform minimum points on the reflected wave curve of the tubing coupling using a gradient descent algorithm, and to determine the propagation speed of the infrasound pulse in the tubing annulus based on the sampling point time corresponding to the multiple minimum points and the length of the tubing coupling.

[0132] Based on the selected depth reference point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse, which is the downhole fluid surface wave reflection point. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then returning.

[0133] The depth of the dynamic fluid level in the oil well is determined based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

[0134] This invention also provides an infrasound-based oil well dynamic fluid level measurement system, the structure of which is as follows: Figure 8 As shown, it includes: an infrasound generator 20, an infrasound receiver 30, and an infrasound-based oil well dynamic fluid level measuring device 10.

[0135] Infrasound generator 20 is used to send infrasound pulses into the annulus of the oil casing;

[0136] Infrasound receiver 30 is used to collect the mixed infrasound pulse signal that is reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends infrasound pulse into the annulus.

[0137] The infrasound-based oil well dynamic fluid level measuring device 10 is used to control the operation of the infrasound generator and the infrasound receiver, and to determine the depth of the oil well dynamic fluid level based on the mixed infrasound pulse signal collected by the infrasound receiver.

[0138] See Figure 3As shown, in the infrasound-based oil well dynamic fluid level measurement device 10, the control processing unit 103 can control the infrasound generator 20 to emit infrasound pulse signals and control the infrasound receiver 20 to receive the returned mixed infrasound pulse signals; the infrasound signal processing unit 102 can perform noise reduction, amplification, filtering, separation, and digital-to-analog conversion on the returned mixed infrasound pulse signals; the control processing unit 103 uses a gradient descent algorithm to calculate and process the tubing coupling reflection wave curve and the oil well fluid level reflection wave curve to determine the propagation velocity and the bottom fluid level reflection time, thereby determining the bottom fluid level depth. The control processing unit 103 establishes a gradient descent algorithm model for the digital infrasound signals reflected from the tubing coupling and fluid level, accurately identifies the extreme values ​​of the infrasound signals reflected from the tubing coupling and fluid level, and calculates the infrasound velocity and dynamic fluid level value within the annular space of the tubing and casing.

[0139] Regarding the infrasound-based oil well dynamic fluid level measuring device in the above embodiments, the specific operation methods of each module have been described in detail in the embodiments of the relevant method, and will not be elaborated here.

[0140] This invention also provides a computer storage medium storing computer-executable instructions, which, when executed by a processor, implement the above-described infrasound-based method for measuring the dynamic fluid level in oil wells.

[0141] This invention also provides a terminal device, including: a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the above-described method for measuring the dynamic fluid level of an oil well based on infrasound.

[0142] Unless otherwise specifically stated, terms such as processing, calculation, operation, determination, display, etc., may refer to the actions and / or processes of one or more processing or computing systems or similar devices that represent the manipulation and conversion of data representing physical (e.g., electronic) quantities within the registers or memory of the processing system into other data similarly representing physical quantities within the memory, registers, or other such information storage, transmission, or display devices of the processing system. Information and signals can be represented using any of a variety of different techniques and methods. For example, data, instructions, commands, information, signals, bits, symbols, and chips mentioned throughout the above description can be represented by voltage, current, electromagnetic waves, magnetic fields or particles, light fields or particles, or any combination thereof.

[0143] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the scope to the specific order or hierarchy described.

[0144] In the detailed description above, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features in a single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, with each claim representing a separate preferred embodiment of the invention.

[0145] Those skilled in the art will also understand that the various illustrative logic blocks, modules, circuits, and algorithm steps described in conjunction with the embodiments herein can be implemented as electronic hardware, computer software, or a combination thereof. To clearly illustrate the interchangeability between hardware and software, the various illustrative components, blocks, modules, circuits, and steps described above are generally described in terms of their functionality. Whether such functionality is implemented as hardware or software depends on the specific application and the design constraints imposed on the overall system. Those skilled in the art can implement the described functionality in alternative ways for each specific application; however, such implementation decisions should not be construed as departing from the scope of this disclosure.

[0146] The steps of the methods or algorithms described in conjunction with the embodiments herein can be directly embodied in hardware, software modules executed by a processor, or a combination thereof. The software modules can reside in RAM memory, flash memory, ROM memory, EPROM memory, EEPROM memory, registers, hard disks, removable disks, CD-ROMs, or any other form of storage medium well known in the art. An exemplary storage medium is connected to the processor, enabling the processor to read information from and write information to the storage medium. Of course, the storage medium can also be a component of the processor. The processor and storage medium can reside in an ASIC. The ASIC can reside in a user terminal. Alternatively, the processor and storage medium can exist as discrete components in the user terminal.

[0147] For software implementation, the techniques described in this application can be implemented using modules (e.g., procedures, functions, etc.) that perform the functions described in this application. This software code can be stored in memory units and executed by a processor. The memory units can be implemented within the processor or outside the processor; in the latter case, they are communicatively coupled to the processor via various means, as is well known in the art.

[0148] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," as interpreted when used as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

Claims

1. A method for measuring the dynamic fluid level in oil wells based on infrasound, characterized in that, include: Acquire the mixed infrasound pulse signal collected by the infrasound receiving device. The mixed infrasound pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends an infrasound pulse into the annulus of the casing. The tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve are separated from the mixed infrasonic pulse signal; The gradient descent algorithm is used to find multiple waveform minima on the reflected wave curve of the tubing coupling. Based on the sampling time corresponding to the multiple minima and the length of the tubing coupling, the propagation speed of the infrasound pulse in the tubing annulus is determined. Based on the selected depth reference point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then return. The depth of the dynamic fluid level in the oil well is determined based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

2. The method as described in claim 1, characterized in that, The acquisition of the mixed infrasound pulse signal collected by the infrasound receiving device includes: Control the infrasound generator to send infrasound pulses into the annulus of the oil jacket; The infrasound receiving device is controlled to receive the mixed infrasound pulse signal reflected back by the oil pipe coupling and the liquid surface; Acquire the mixed infrasound pulse signal received by the infrasound receiving device.

3. The method as described in claim 1, characterized in that, The separation of the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasonic pulse signal includes: The mixed infrasonic pulse signal is subjected to noise reduction, amplification and filtering to obtain the separated infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface; The infrasonic pulse signals reflected by the separated tubing coupling and the infrasonic pulse signals reflected by the oil well fluid surface are processed by analog-to-digital conversion to obtain the reflection wave curves of the tubing coupling and the oil well fluid surface.

4. The method as described in claim 3, characterized in that, The process of performing analog-to-digital conversion on the separated infrasonic pulse signals reflected from the tubing coupling and the infrasonic pulse signals reflected from the oil well fluid surface yields the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve, including: The analog-to-digital conversion unit samples the infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface at a specific sampling frequency. During the sampling process, the pulse signal value at the sampling point is processed by analog-to-digital conversion to obtain the corresponding digital signal value. Based on the digital signal value at the sampling point, the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve are formed.

5. The method as described in claim 1, characterized in that, The step involves using a gradient descent algorithm to find multiple waveform minima on the reflected wave curve of the tubing coupling, and determining the propagation speed of the infrasonic pulse within the annulus based on the sampling time corresponding to these minima and the length of the tubing coupling. This includes: From the reflected wave curves of the tubing coupling, select the reflected wave curve of the tubing coupling with a stable front end, select a current sampling point n-1, and use a first-order descent algorithm to calculate the time axis coordinate of the next sampling point n: Where: X n X represents the time axis coordinate of the nth sampling point of the reflected wave curve of the oil pipe coupling. n-1 The time axis coordinate of the (n-1)th sampling point of the reflected wave curve of the oil pipe coupling; a is a constant; The derivative of the signal value at the (n-1)th sampling point of the reflected wave curve of the tubing coupling: Where, f(X) n-1 f(X) represents the signal value at the (n-1)th sampling point. n-2 ) represents the signal value at the (n-2)th sampling point; Based on the calculated time axis coordinates of sampling point n, the signal value of sampling point n is determined. If the signal value of sampling point n is less than the signal value of sampling point n-1, sampling point n is taken as the current sampling point, and the process continues to execute the step of calculating the time axis coordinates of the next sampling point using the first-order step descent algorithm, until the signal value of the next sampling point is greater than the signal value of the current sampling point. Then the current sampling point is a local minimum point. Repeat the above process of determining a minimum point multiple times until the minimum point of multiple stable waveforms in the tubing coupling reflection wave curve is found; determine the propagation speed of the infrasonic pulse in the tubing annulus based on the minimum point of the multiple stable waveforms.

6. The method as described in claim 1, characterized in that, Determining the propagation speed of the infrasonic pulse in the annulus based on the minimum points of the multiple waveform segments includes: From a series of consecutive minimum points of waveforms, select g minimum points. Mark N as the time axis coordinate of the sampling point corresponding to the minimum point of the first coupling wave reflection curve, and mark M as the time axis coordinate of the sampling point of the minimum point of the g-th coupling wave reflection curve. Then, the time it takes for the infrasound reflected wave to pass through g consecutive oil pipe couplings can be calculated as follows: t1 = (MN)·T, Where: T is the sampling time interval, then f is the sampling frequency of the analog-to-digital conversion unit for the infrasonic pulse signal reflected by the tubing coupling and the infrasonic pulse signal reflected by the oil well fluid surface; Therefore, the propagation speed of infrasound in the annulus is: Where L is the average length of the downhole tubing coupling.

7. The method as described in claim 1, characterized in that, Based on the selected depth reference point, a gradient descent algorithm is used to reverse-engineer the first minimum point on the oil well fluid surface reflection wave curve. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to return after being reflected by the oil well fluid surface, including: Based on the time axis coordinates of the reference point corresponding to the selected depth reference point on the reflected wave curve, the minimum point is found by reverse searching using the first-order gradient descent algorithm, and the time axis coordinates of the sampling point corresponding to the minimum point are marked as Y. Based on the sampling time corresponding to the first local minimum point found, the reflection time t2 of the infrasound pulse is determined using the following formula.

8. The method as described in claim 1, characterized in that, The determination of the depth of the dynamic fluid level in the oil well based on the propagation velocity and reflection time of the infrasonic pulse in the annulus includes: Based on the propagation velocity v of the infrasonic pulse in the annulus and the reflection time t2 of the infrasonic pulse, the depth of the dynamic fluid level in the oil well is determined using the following formula:

9. A device for measuring the dynamic fluid level in an oil well based on infrasound, characterized in that, include: The infrasound acquisition unit is used to acquire the mixed infrasound pulse signal collected by the infrasound receiving device. The mixed infrasound pulse signal is the signal reflected back by the tubing coupling and the oil well fluid surface after the infrasound generator sends the infrasound pulse into the annulus. The infrasound signal processing unit is used to separate the tubing coupling reflection wave curve and the oil well fluid surface reflection wave curve from the mixed infrasound pulse signal. The control processing unit is used to find multiple waveform minima on the reflected wave curve of the tubing coupling using a gradient descent algorithm, and to determine the propagation speed of the infrasound pulse in the tubing annulus based on the sampling time corresponding to the multiple minima and the length of the tubing coupling. Based on the selected depth reference point, the gradient descent algorithm is used to find the first minimum point on the oil well fluid surface reflection wave curve in reverse, which is the downhole fluid surface wave reflection point. The reflection time of the infrasonic pulse is determined according to the sampling point time corresponding to the found minimum point. The reflection time is the time taken for the infrasonic wave to travel from emission to being reflected by the oil well fluid surface and then returning. The depth of the dynamic fluid level in the oil well is determined based on the propagation speed of the infrasonic pulse in the annulus and the reflection time of the infrasonic pulse.

10. A system for measuring the dynamic fluid level in oil wells based on infrasound, characterized in that, include: The infrasound generator, the infrasound receiver, and the infrasound-based oil well dynamic fluid level measuring device as described in claim 9 Infrasound generator, used to send infrasound pulses into the annulus of the oil casing; The infrasound receiving device is used to collect the mixed infrasound pulse signal that is reflected back by the tubing coupling and the oil well fluid surface after the infrasound pulse is sent into the annulus by the infrasound generator. The infrasound-based oil well dynamic fluid level measurement device is used to control the operation of the infrasound generator and the infrasound receiver, and to determine the depth of the oil well dynamic fluid level based on the mixed infrasound pulse signal collected by the infrasound receiver.

11. A computer storage medium, characterized in that, The computer storage medium stores computer-executable instructions, which, when executed by a processor, implement the infrasound-based oil well dynamic fluid level measurement method according to any one of claims 1-8.

12. A terminal device, characterized in that, include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor, when executing the program, implements the infrasound-based method for measuring the dynamic fluid level in an oil well as described in any one of claims 1-8.

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