A horizontal well acoustic velocity correction method and system for formation alteration

Abstract

The application discloses a kind of horizontal well sound velocity correction method and system for stratum alteration, waveform velocity analysis is carried out to monopole acoustic wave full wave train array data, and the apparent time difference of stratum P-wave is obtained;The corresponding apparent time difference under different alteration stratum and original stratum velocity ratio conditions is calculated;The curve of corresponding apparent time difference under different velocity ratio conditions is fitted by composite natural logarithm, and the fitting curve under different velocity ratio is obtained, and the stratum velocity correction chart of alteration radius, apparent time difference and stratum true time difference ratio is obtained according to the fitting curve;The stratum invasion radius is determined in combination with electrical logging geological data, and the apparent time difference of actual stratum target layer section at different depth positions is calculated according to time-slow correlation method;The invasion radius of a certain depth position is substituted into the stratum velocity correction chart, and the stratum true time difference value at the corresponding depth position is obtained in combination with the apparent time difference of the corresponding depth position, as the acoustic time difference of original stratum.The application is simple and convenient to calculate, and is suitable for large amount of field data processing.

Description

Technical Field

[0001] The present invention belongs to the field of applied geophysics technology, and in particular relates to a horizontal well acoustic velocity correction method and system for formation alteration. Background Art

[0002] With the advancement of drilling technology, the unique advantages of horizontal wells have increasingly attracted attention from oilfield operators. To fully exploit reservoir potential and improve oil and gas recovery, horizontal well drilling has become a widespread practice across major oilfields. However, the increasing number of horizontal wells presents new challenges for interpretation engineers. First, the wellbore and formation environments in horizontal wells differ significantly from those in vertical wells, significantly altering the response characteristics. In vertical wells, the formation model can be assumed to be an isotropic homogeneous body, with the logging instrument axis perpendicular or approximately perpendicular to the formation horizontal plane. The formation, wellbore, and mud invasion shapes are all assumed to be rotationally symmetric about the instrument axis. However, in horizontal wells, the instrument axis is no longer perpendicular to the formation plane, and the symmetry of the wellbore and mud invasion shapes no longer exists. Therefore, it is impossible to directly apply vertical well logging technology to the oil and gas evaluation of horizontal wells. Second, existing interpretation models are no longer applicable to horizontal wells, making accurate determination of formation parameters a challenge in horizontal well interpretation. For example, the acoustic velocity of the formation is one of the important methods for evaluating reservoir properties, and it has a significant negative impact on subsequent radial velocity profiles and acoustic long-range detection logging evaluations.

[0003] During logging in horizontal wells, the relative spatial position relationship between the instrument and the formation changes. The combined influence of factors such as mud invasion and lithologic changes makes the logging response in horizontal wells extremely complex. The measured formation acoustic wave velocity is no longer equal to the original formation acoustic wave velocity. Therefore, studying the acoustic velocity variation law and correction method caused by mud invasion and lithologic combination in horizontal wells has become a key technical issue that must be solved at present.

[0004] At present, for the problem of well logging acoustic velocity correction, Lin Weijun et al. (2006) and Wei Zhituo et al. (2015) carried out the research on the borehole sound field response propagation law of different stratum inclination in straight well and layered stratum in inclined well (Lin Weijun, Wang Xiuming, Zhang Hailan. Study on borehole sound field in inclined stratum [J]. Chinese Journal of Geophysics, 2006, 49(1): 284-294), the latter established the acoustic velocity correction method for non-uniform layered stratum and gave the correction chart (Wei Zhituo, Chen Xuelian. Analysis of borehole sound field under inclined stratum and making of acoustic velocity correction chart [J]. Acta Acustica Sinica, 2015, 40(3): 9). In 2016, Yang Xin discussed the acoustic velocity variation law caused by high and low velocity stratum combination near the well in his master's thesis, but did not give the acoustic velocity correction scheme (Yang Xin. Master's thesis: time difference correction method for acoustic logging in horizontal and high-angle deviated wells [D]. China University of Petroleum (Beijing), 2016). Taking the mud invasion as an example, in the straight well, it is generally believed that under the action of the pressure difference between the mud in the well and the stratum, the mud will invade into the permeable stratum, and the invasion depth is uniformly distributed around the well axis. In the horizontal well, affected by multiple factors such as stratum permeability, pressure difference between mud in the well and stratum, and gravity, the mud invasion profile is no longer the annular well symmetry profile in the straight well, but presents an asymmetric invasion profile, and with the increase of mud invasion time, the invasion radius on one side of the wellbore is greater than that on the other side. The mud invasion profile shape generally has an "ellipse" shape and a "teardrop" shape, therefore, it is necessary to analyze the influence of the invasion degree on the acoustic velocity and make correction, and the same is true for the lithology combination of the stratum in the horizontal well. In general, for the problem that the acoustic velocity of the original stratum cannot be accurately and reliably obtained due to the acoustic velocity differentiation caused by mud invasion, lithology combination and other factors, there is no report on the specific acoustic velocity correction scheme. SUMMARY

[0005] The technical problem to be solved by the present application is to provide a horizontal well acoustic velocity correction method and system for stratum alteration, to solve the technical problem that the original stratum velocity cannot be accurately obtained due to mud invasion and different lithology combinations, and to provide a more real stratum velocity model for subsequent radial velocity profile and acoustic wave far detection logging.

[0006] The present application adopts the following technical scheme:

[0007] A horizontal well acoustic velocity correction method for stratum alteration, comprising the following steps:

[0008] S1, waveform velocity analysis is performed on the monopole acoustic full wave train array data to obtain the longitudinal wave apparent time difference of the stratum;

[0009] S2. Based on the P-wave apparent time difference of the formation obtained in step S1, calculate the corresponding apparent time difference under different velocity ratios between the altered formation and the original formation;

[0010] S3, performing composite natural logarithm fitting on the curves corresponding to the apparent moveout under different velocity ratios obtained in step S2 to obtain fitting curves under different velocity ratios, and obtaining a formation velocity correction chart of the ratio of the alteration radius to the apparent moveout and the true moveout of the formation based on the fitting curves;

[0011] S4. Determine the formation invasion radius by combining the electrical logging geological data, and calculate the apparent time difference at different depths of the actual formation target interval based on the time-slow correlation method;

[0012] S5. Substitute the invasion radius of a certain depth position determined in step S4 into the formation velocity correction chart obtained in step S3 to obtain the ratio of the formation apparent time difference to the formation true time difference. Combined with the apparent time difference at the corresponding depth position in step S4, the formation true time difference value at the corresponding depth position is obtained as the acoustic wave time difference of the original formation.

[0013] Specifically, in step S1, array acoustic logging is performed in the logging depth interval to obtain monopole acoustic full wave array data.

[0014] Furthermore, the apparent time difference of the longitudinal wave of the formation ρ(s,T) is calculated as follows:

[0015]

[0016] Among them, X m (t) is the mth receiving transducer in the N receiving transducer array, d is the spacing between transducers, [T,T w ] is the time window.

[0017] Specifically, step S2 is as follows:

[0018] Different altered formation radius ranges were set; the velocity ratio between the altered formation and the undisturbed formation was set; the wellbore monopole array waveforms corresponding to different velocity ratios under different altered radii were obtained using three-dimensional finite difference numerical simulation technology, and the apparent time difference corresponding to different velocity ratios between the altered formation and the undisturbed formation was calculated using the time-slow correlation method.

[0019] Furthermore, the velocity ratio of the altered formation to the undisturbed formation includes two situations: the velocity of the altered formation is greater than the velocity of the undisturbed formation; and the velocity of the altered formation is less than the velocity of the undisturbed formation.

[0020] Specifically, in step S3, when the velocity of the altered formation is greater than the velocity of the original formation:

[0021]

[0022] Wherein, y is the ratio of apparent time difference and formation original formation time difference, y0 is the constant coefficient obtained by fitting, A is the constant coefficient obtained by fitting, w is the constant coefficient obtained by fitting, x is the formation alteration radius, and c is the constant coefficient obtained by fitting.

[0023] Specifically, in step S3, when the altered formation velocity is less than the original formation velocity:

[0024]

[0025] Wherein, y is the ratio of apparent time difference and formation original formation time difference, y0 is the constant coefficient obtained by fitting, A is the constant coefficient obtained by fitting, w is the constant coefficient obtained by fitting, x is the formation alteration radius, and c is the constant coefficient obtained by fitting.

[0026] In a second aspect, an embodiment of the present application provides a horizontal well sound velocity correction system for formation alteration, characterized in that it comprises:

[0027] A data module, which performs waveform velocity analysis on monopole acoustic full wave train array data to obtain the P-wave apparent time difference of the formation;

[0028] A first calculation module, which calculates the corresponding apparent time difference under different altered formation and original formation velocity ratio conditions based on the P-wave apparent time difference of the formation obtained by the data module;

[0029] A fitting module, which performs compound natural logarithm fitting on the curve of the corresponding apparent time difference under different velocity ratio conditions obtained by the calculation module to obtain a fitting curve under different velocity ratios, and obtains a formation velocity correction chart of the altered radius and the ratio of the apparent time difference and the true time difference of the formation according to the fitting curve;

[0030] A second calculation module, which determines the formation intrusion radius in combination with electrical logging geological data, and calculates the apparent time difference of different depth positions of the actual formation target layer section according to the time-slow correlation method;

[0031] A correction module, which substitutes the intrusion radius of a certain depth position determined by the second calculation module into the formation velocity correction chart obtained by the fitting module to obtain the ratio of the formation apparent time difference and the true time difference, and obtains the true time difference value of the formation at the corresponding depth position in combination with the apparent time difference of the corresponding depth position by the second calculation module, as the acoustic time difference of the original formation.

[0032] Specifically, the P-wave apparent time difference of the formation obtained by the data module is as follows:

[0033]

[0034] Wherein, X m (t) is the mth receiving transducer in the N receiving transducer array, d is the interval between the transducers, and [T, T w] is the time window.

[0035] Specifically, the fitting module obtains fitting curves under different speed ratios including:

[0036] When the velocity of the altered formation is greater than the velocity of the original formation:

[0037]

[0038] When the velocity of the altered formation is less than the velocity of the original formation:

[0039]

[0040] Among them, y is the ratio of the apparent time difference to the original formation time difference, y0 is the constant coefficient obtained by fitting, A is the constant coefficient obtained by fitting, w is the constant coefficient obtained by fitting, x is the formation alteration radius, and c is the constant coefficient obtained by fitting.

[0041] Compared with the prior art, the present invention has at least the following beneficial effects:

[0042] A horizontal well sound velocity correction method for formation alteration is provided. By constructing a diagram of the variation law of apparent acoustic wave time difference of different formations and combining it with data such as invasion radius to obtain the true time difference value of the formation, a horizontal well sound velocity correction method for formation alteration is formed, achieving the purpose of the invention. Compared with traditional technologies, the original formation velocity under arbitrary alteration conditions can be conveniently obtained based on the established theoretical diagram of sound velocity correction. The calculation is fast and convenient, and is suitable for large-scale field data processing. Numerical simulation and composite natural logarithm fitting technology are applied to the analysis of curve variation law, avoiding errors that may be caused by traditional interpolation calculation methods, and the calculation results are more accurate. Combining other electrical measurement data, the formation invasion radius is estimated, and substituting it into the theoretical diagram to obtain corrected continuous sound velocity data, making the data more portable and having a wider range of applications.

[0043] Furthermore, when the velocity of the altered formation is greater than the velocity of the original formation, the change curve of the ratio of the alteration radius to the apparent time difference and the true formation time difference for any erosion diameter and velocity ratio is obtained, so that the formation velocity correction plate of the ratio of the alteration radius to the apparent time difference and the true formation time difference can be obtained, realizing automatic calculation and correction, avoiding interpolation processing in the plate, and having stronger applicability.

[0044] Furthermore, when the velocity of the altered formation is less than the velocity of the original formation, the variation curve of the ratio of the alteration radius to the apparent time difference and the true formation time difference for any erosion diameter change and velocity ratio is obtained, thereby obtaining a formation velocity correction plate of the ratio of the alteration radius to the apparent time difference and the true formation time difference, realizing automatic calculation and correction, avoiding interpolation processing in the plate, and having stronger applicability.

[0045] It can be understood that the beneficial effects of the second aspect mentioned above can be found in the relevant description of the first aspect mentioned above, and will not be repeated here.

[0046] In summary, the method of the present invention is simple and convenient in calculation, fast and practical, suitable for large-scale processing of field data, and can provide a key basis for determining acoustic porosity, accurately extracting the arrival time of longitudinal wave radial velocity profiles, and constructing velocity profiles for long-range acoustic detection.

[0047] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0048] Figure 1 This is a workflow diagram of the horizontal well acoustic velocity correction method for formation alteration according to the present invention;

[0049] Figure 2 The comparison diagrams of the wellbore monopole waveforms at different alteration radii when the source distance is 1.5m, among which (a) is the comparison diagram of the wellbore monopole waveforms at different alteration radii when the source distance is 1.5m, and (b) is the enlarged diagram of (a) from 0 to 550us;

[0050] Figure 3 Figure 2 is a graph showing the relationship between alteration radius and apparent velocity / apparent time difference, where (a) is a graph showing the time difference variation of water-saturated and gas-saturated formations at different invasion radii, and (b) is a graph showing the fitting relationship between invasion radius and apparent time difference.

[0051] Figure 4 This is a fitting relationship curve diagram of different alteration radii and apparent velocity / apparent time difference ratios when the altered formation velocity is greater than the original formation velocity;

[0052] Figure 5 This is a fitting relationship curve diagram of different alteration radii and apparent velocity / apparent time difference ratio when the altered formation velocity is less than the original formation velocity;

[0053] Figure 6 The waveforms of the wellbore monopole array corresponding to the ratio of the altered formation velocity to the original formation velocity at different alteration radii are shown in Figure 1, where (a) is 1:1.2 and (b) is 1:2.2.

[0054] Figure 7 This is a comparison chart of the measured data before and after time difference correction. DETAILED DESCRIPTION

[0055] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of them. All other embodiments obtained by ordinary technicians in this field based on the embodiments of the present invention without making any creative efforts shall fall within the scope of protection of the present invention.

[0056] In the description of the present application, it should be understood that the terms "include" and "contain" indicate the presence of described features, whole, steps, operations, elements and / or components, but do not exclude the presence or addition of one or more other features, whole, steps, operations, elements, components and / or sets thereof.

[0057] It should also be understood that the terms used in the present application specification are only for the purpose of describing specific embodiments and are not intended to limit the present application. As used in the present application specification and the appended claims, the singular forms "a", "an" and "the" are intended to include the plural forms unless the context clearly indicates otherwise.

[0058] It should be further understood that the term "and / or" used in the present application specification and the appended claims means one or more of the associated listed items and all possible combinations thereof, and includes these combinations, for example, A and / or B can mean: A exists alone, A and B exist together, B exists alone. In addition, the character " / " in the present application generally represents an "or" relationship between the front and rear associated objects.

[0059] It should be understood that although the terms first, second, third, etc. may be used in the embodiments of the present application to describe certain ranges, etc., these ranges should not be limited to these terms. These terms are only used to distinguish the ranges from each other. For example, the first range can also be referred to as the second range, and similarly, the second range can also be referred to as the first range without departing from the scope of the embodiments of the present application.

[0060] Depending on the context, the word "if" as used herein can be interpreted to mean "when" or "while" or "in response to determining" or "in response to detecting". Similarly, the phrase "if determined" or "if detecting (a stated condition or event)" can be interpreted to mean "when determined" or "in response to determining" or "when detecting (a stated condition or event)" or "in response to detecting (a stated condition or event)", depending on the context.

[0061] Various structural diagrams according to the disclosed embodiments of the present application are shown in the accompanying drawings. These drawings are not drawn to scale, in which certain details are exaggerated for the purpose of clear expression, and certain details can be omitted. The shapes of various regions, layers and their relative size and positional relationship shown in the drawings are only exemplary, and in actuality, there can be deviations due to manufacturing tolerances or technical limitations, and a person skilled in the art can additionally design regions / layers with different shapes, sizes, relative positions according to actual needs.

[0062] In order to solve the problem that the original formation acoustic velocity cannot be accurately and reliably obtained due to the formation acoustic velocity differentiation caused by mud invasion, lithology combination and other factors, the application provides a horizontal well acoustic velocity correction method for formation alteration, through a large amount of numerical simulation calculation and theoretical analysis, a theoretical chart for acoustic velocity correction is obtained, the original formation velocity under any alteration and diameter conditions can be conveniently obtained, the calculation is simple, convenient, fast and practical, is suitable for a large amount of field data processing, solves the technical problem that the original formation acoustic velocity cannot be accurately obtained due to mud invasion and lithology combination, fills the blank in the related field, realizes automatic calculation and correction, avoids interpolation processing in the chart, is more suitable, provides a key basis for determination of acoustic porosity, accurate extraction of P-wave radial velocity profile and construction of acoustic velocity profile for acoustic far detection.

[0063] The horizontal well acoustic velocity correction method for formation alteration can accurately and quickly obtain the original formation acoustic velocity of the formation, and comprises the following steps:

[0064] S1, waveform velocity analysis is performed on the obtained monopole acoustic full wave train array data to obtain the P-wave apparent time difference of the formation;

[0065] The method for obtaining the monopole acoustic full wave train array data is that array acoustic logging is performed in a logging depth interval to obtain the monopole acoustic full wave train array data;

[0066] The P-wave apparent time difference is calculated by using the time-slow correlation method shown in formula (1), and formula (1) is expressed as:

[0067]

[0068] Wherein, X m (t) is the mth receiving transducer in the N receiving transducer array, and d is the interval between the transducers.

[0069] The position T of a given time window T w and a certain time difference value s in the slowness interval are given, and the calculation process of the correlation function is as follows:

[0070] In the molecular part, the waveform data X m (t) on each receiver (1<m≤N) is propagated back in time, or the waveform is moved forward on the time axis by s(m-1)d to the position of the first receiver.

[0071] Next, the N data points (the data received by the first transducer plus N-1 waveform data points processed by time shifting) are added and summed;

[0072] Then, the absolute value of the sum is calculated and squared, and the integral of the sum in the time window [T, T w ] is calculated.

[0073] In the denominator, the operation of the waveform propagating back in time remains unchanged, except that the square of the absolute value of each point in the waveform is taken first, and then the squared data are superimposed and the value of the squared value in [T, T w ] on the integral;

[0074] Repeat the above numerator and denominator operations for all time difference s values ​​in the slowness interval;

[0075] Next, let the time window T w The position T changes, and the time variable T is the time window T w The midpoint of the time window is used to repeat the above process for the waveform within a given period of time according to a certain time step (in actual operation, T w It usually includes two to three cycles of the waveform, and the time step is generally T w half of the total cost).

[0076] S2. Calculate the corresponding apparent time difference under different velocity ratios between altered strata and undisturbed strata;

[0077] Calculate the corresponding apparent time difference method under different velocity ratios of altered formations and original formations (velocity is equal to the inverse of time difference):

[0078] First, different radius ranges of altered formations are set;

[0079] Secondly, the velocity ratio of the altered formation to the original formation is set, including two cases: the velocity of the altered formation is greater than the velocity of the original formation and the velocity of the altered formation is less than the velocity of the original formation;

[0080] Finally, the three-dimensional finite difference numerical simulation technology is used to obtain the corresponding wellbore monopole array waveforms under different alteration radii and different velocity ratios. The time-slow correlation method shown in step S1 is used to calculate the P-wave apparent time difference, and the P-wave apparent time difference of the formation is calculated based on this.

[0081] S3, performing composite natural logarithm fitting on the apparent time difference curves at different speed ratios to obtain fitting curves at different speed ratios;

[0082] When the velocity of the altered formation is greater than the velocity of the original formation:

[0083]

[0084] When the velocity of the altered formation is less than the velocity of the original formation:

[0085]

[0086] Wherein, y is the ratio of the apparent time difference obtained in step S1 to the original formation time difference of the formation, which is dimensionless; x is the formation alteration radius, in meters; y0=260.827, c=0.01, w=0.94, and A=1.815 are constant coefficients obtained by fitting; and π is the pi.

[0087] According to the above formulas (2) and (3), the variation curve of the alteration radius and the ratio of the apparent moveout to the true moveout of the formation for any etching diameter and velocity ratio can be obtained, thereby obtaining the formation velocity correction chart of the alteration radius and the ratio of the apparent moveout to the true moveout of the formation.

[0088] S4. Determine the approximate radius of formation invasion by combining electrical logging and other data, and calculate the actual formation apparent time difference based on the time-slow correlation method;

[0089] The formation invasion radius is determined based on other logging and geological data such as electrical logging, and the apparent time difference of different depth positions of the actual formation target layer section is calculated based on the time-slow correlation method provided in step S1.

[0090] S5. Substitute the chart into the chart to calculate the ratio of the apparent formation time difference to the true formation time difference, and obtain the true formation time difference value.

[0091] Substitute the invasion radius of a certain depth position determined in step S4 into the sound velocity correction chart obtained in step S3, and use the linear difference method to calculate the ratio of the apparent time difference of the formation to the true time difference of the formation. Combined with the apparent time difference of the corresponding depth position in step S4, the true time difference value of the formation at the corresponding depth position is obtained, which is the acoustic wave time difference of the original formation.

[0092] In another embodiment of the present invention, a horizontal well sound velocity correction system for formation alteration is provided. The system can be used to implement the above-mentioned horizontal well sound velocity correction method for formation alteration. Specifically, the horizontal well sound velocity correction system for formation alteration includes a data module, a first calculation module, a fitting module, a second calculation module and a correction module.

[0093] Among them, the data module performs waveform velocity analysis on the monopole acoustic wave full wave array data to obtain the longitudinal wave apparent time difference of the formation;

[0094] The data module obtains the apparent time difference of longitudinal waves of the formation ρ(s,T) as follows:

[0095]

[0096] Among them, X m (t) is the mth receiving transducer in the N receiving transducer array, d is the spacing between transducers, [T,T w ] is the time window.

[0097] The first calculation module calculates the corresponding apparent time difference under different velocity ratios between the altered stratum and the original stratum based on the P-wave apparent time difference of the stratum obtained by the data module;

[0098] The fitting module performs composite natural logarithm fitting on the curves corresponding to the apparent time difference under different velocity ratios obtained by the calculation module to obtain fitting curves under different velocity ratios. Based on the fitting curves, a formation velocity correction chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained;

[0099] The fitting module obtains the fitting curves under different speed ratios, including:

[0100] When the velocity of the altered formation is greater than the velocity of the original formation:

[0101]

[0102] When the velocity of the altered formation is greater than the velocity of the original formation:

[0103]

[0104] Among them, y is the ratio of the apparent time difference to the original formation time difference, y0 is the constant coefficient obtained by fitting, A is the constant coefficient obtained by fitting, w is the constant coefficient obtained by fitting, x is the formation alteration radius, and c is the constant coefficient obtained by fitting.

[0105] The second calculation module combines the electrical logging geological data to determine the formation invasion radius and calculates the apparent time difference at different depths of the actual formation target layer using the time-slow correlation method;

[0106] The correction module substitutes the invasion radius of a certain depth position determined by the second calculation module into the formation velocity correction plate obtained by the fitting module to obtain the ratio of the formation apparent time difference to the formation true time difference. Combined with the apparent time difference at the corresponding depth position of the second calculation module, the formation true time difference value at the corresponding depth position is obtained as the acoustic wave time difference of the original formation.

[0107] In another embodiment of the present invention, a terminal device is provided, which includes a processor and a memory, wherein the memory is used to store a computer program, the computer program includes program instructions, and the processor is used to execute the program instructions stored in the computer storage medium. The processor may be a central processing unit (CPU), or may be other general-purpose processors, digital signal processors (DSP), application-specific integrated circuits (ASIC), field-programmable gate arrays (FPGA), or other programmable logic devices, discrete gates or transistor logic devices, discrete hardware components, etc. It is the computing core and control core of the terminal, which is suitable for implementing one or more instructions, specifically suitable for loading and executing one or more instructions to implement corresponding method processes or corresponding functions; the processor described in the embodiment of the present invention can be used for the operation of a horizontal well acoustic velocity correction method for formation alteration, including:

[0108] Waveform velocity analysis is performed on the monopole acoustic full-wave array data to obtain the longitudinal wave apparent time difference of the formation; based on the longitudinal wave apparent time difference of the formation, the corresponding apparent time difference under different velocity ratios between the altered formation and the original formation is calculated; the curves corresponding to the apparent time difference under different velocity ratios are subjected to composite natural logarithm fitting to obtain fitting curves under different velocity ratios, and a formation velocity correction plate of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained based on the fitting curve; the formation invasion radius is determined in combination with the electrical logging geological data, and the apparent time difference of the actual formation target layer at different depth positions is calculated based on the time-slow correlation method; the invasion radius at a certain depth position is substituted into the formation velocity correction plate to obtain the ratio of the formation apparent time difference to the formation true time difference, and the formation true time difference value at the corresponding depth position is obtained in combination with the apparent time difference at the corresponding depth position, which is used as the acoustic wave time difference of the original formation.

[0109] In another embodiment of the present invention, the present invention further provides a storage medium, specifically a computer-readable storage medium (Memory), which is a memory device in a terminal device for storing programs and data. It can be understood that the computer-readable storage medium here can include both the built-in storage medium in the terminal device and, of course, the extended storage medium supported by the terminal device. The computer-readable storage medium provides a storage space, which stores the operating system of the terminal. In addition, one or more instructions suitable for being loaded and executed by the processor are also stored in the storage space. These instructions can be one or more computer programs (including program codes). It should be noted that the computer-readable storage medium here can be a high-speed RAM memory or a non-volatile memory (Non-Volatile Memory), such as at least one disk memory.

[0110] The processor may load and execute one or more instructions stored in a computer-readable storage medium to implement the corresponding steps of the horizontal well acoustic velocity correction method for formation alteration in the above embodiment. The processor may load and execute the following steps:

[0111] Waveform velocity analysis is performed on the monopole acoustic full-wave array data to obtain the longitudinal wave apparent time difference of the formation; based on the longitudinal wave apparent time difference of the formation, the corresponding apparent time difference under different velocity ratios between the altered formation and the original formation is calculated; the curves corresponding to the apparent time difference under different velocity ratios are subjected to composite natural logarithm fitting to obtain fitting curves under different velocity ratios, and a formation velocity correction plate of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained based on the fitting curve; the formation invasion radius is determined in combination with the electrical logging geological data, and the apparent time difference of the actual formation target layer at different depth positions is calculated based on the time-slow correlation method; the invasion radius at a certain depth position is substituted into the formation velocity correction plate to obtain the ratio of the formation apparent time difference to the formation true time difference, and the formation true time difference value at the corresponding depth position is obtained in combination with the apparent time difference at the corresponding depth position, which is used as the acoustic wave time difference of the original formation.

[0112] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Generally, the components of the embodiments of the present invention described and shown in the drawings herein can be arranged and designed in various different configurations. Therefore, the following detailed description of the embodiments of the present invention provided in the drawings is not intended to limit the scope of the claimed invention, but merely represents selected embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of the present invention.

[0113] In order to understand the basic principle of the present invention, numerical simulation is used to illustrate the method basis of the horizontal well acoustic velocity correction method for formation alteration proposed by the present invention.

[0114] S1. Perform waveform velocity analysis on the acquired monopole acoustic full wave array data to obtain the longitudinal wave apparent time difference of the formation;

[0115] Table 1 shows the formation elastic parameters and formation density used in numerical calculations;

[0116]

[0117] Taking the gas-bearing formation as an example, the velocity of the altered formation is set as the formation 3 in Table 1 and the original formation is set as the formation 2 in Table 1, with a velocity ratio of 1.46:1. The wellbore monopolar waveforms under 19 alteration radii and uniformly saturated gas and water formations are calculated, as shown in the following figure: Figure 2 As shown in the figure, the comparison shows that with the increase of the alteration radius, the formation arrival time gradually increases and the acoustic wave amplitude increases; when the alteration radius reaches a certain value, the arrival time and amplitude of the first wave of the waveform no longer change; when the alteration radius is small, the travel time or time difference is controlled by the original low-speed formation.

[0118] For the above 19 types of alteration and 2 types of uniform formation monopole array waveforms, the time-slow correlation method is used to extract the compressional wave time difference according to step S1. Figure 3This further confirms the above conclusions and insights, particularly the finding that the alteration velocity limit is approximately one wavelength (e.g., with a formation velocity of 3850 m / s and an acoustic excitation frequency of 20,000 Hz, the maximum estimated wavefield is 3850 / 20,000 = 0.1925 m). Furthermore, by analyzing the alteration radius (referred to as the intrusion radius) and the apparent moveout at the bottom of the horizontal well, the two satisfy a composite natural logarithmic relationship (see Equation 2). This yields curves of the intrusion radius and apparent moveout for different velocity ratios, providing the theoretical basis for the acoustic velocity correction chart when the altered formation velocity exceeds the undisturbed formation velocity. A similar process occurs when the altered formation velocity is less than the undisturbed formation velocity.

[0119] S2. Calculate the corresponding apparent time difference method under different velocity ratios between altered strata and undisturbed strata (the velocity is equal to the inverse of the time difference):

[0120] First, different altered formation radii are set from 0 m (representing that the formation is altered and there is no change in formation velocity perpendicular to the well) to 0.4 m (representing that the formation altered radius is 0.4 m and the undisturbed formation velocity is different from the altered formation velocity), e.g. Figure 4 and Figure 5 horizontal axis;

[0121] Secondly, set the velocity ratio of the altered formation to the original formation. When the velocity of the altered formation is greater than that of the original formation, set the velocity ratio of the two to 1.2:1, 1.4:1, 1.6:1, 1.8:1, 2.0:1, and 2.2:1, respectively. Figure 4 As shown in the figure; when the velocity of the altered formation is less than that of the original formation, the velocity ratios of the two are set to 1:1.2, 1:1.4, 1:1.6, 1:1.8, 1:2.0, and 1:2.2 respectively. Figure 5 As shown;

[0122] Finally, the three-dimensional finite difference numerical simulation technology is used to obtain the corresponding wellbore monopole array waveforms under different velocity ratios at different alteration radii, such as Figure 6 As shown in the figure, the time-slow correlation method shown in step S1 is used to calculate the P-wave apparent time difference, and the P-wave apparent time difference of the formation under all alteration diameter changes and velocity ratios is calculated. Figure 4 The different marks at different velocity ratios shown are the ratios of the obtained apparent formation moveout to the original formation true moveout set in the numerical simulation.

[0123] S3, performing composite natural logarithm fitting on the apparent time difference curves at different speed ratios to obtain fitting curves at different speed ratios; Figure 4 and Figure 5 The fitting relationship curves of different alteration radii and apparent velocity / apparent time difference ratios are given respectively, which are composite natural logarithm fitting.

[0124] S4. The invasion radius of the formation can be inverted based on the resistivity logging. At the same time, the time-slow correlation method provided in step S1 is used to calculate the P-wave apparent time difference result of the target layer segment.

[0125] S5. Substituting the chart into the chart, calculate the ratio of the apparent formation time difference to the true formation time difference, and obtain the true formation time difference value; Figure 7 The results of the P-wave time difference correction for a certain well are given. It can be seen that there are obvious differences before and after correction, which will have a significant impact on the subsequent data processing and application based on the time difference curve.

[0126] The method provided by the present invention is a theoretical plate for sound velocity correction obtained through a large number of numerical simulation calculations and theoretical analysis. The theoretical plate can be represented by a composite natural logarithm, and automatic calculation and correction are achieved, thus avoiding interpolation processing in the plate and having stronger applicability. In particular, the alteration radius required for the correction model can be simply estimated through data such as resistivity logging, thereby realizing continuous correction and calculation of the logging profile.

[0127] In summary, the method and system for correcting acoustic velocity in horizontal wells for formation alteration of the present invention have the following effects:

[0128] (1) The present invention solves the problem of being unable to accurately obtain the original formation sound velocity caused by mud invasion and lithologic combination. The method uses finite difference numerical simulation of the sound field without invasion radius and lithologic combination and time difference extraction processing based on the sound field to draw a sound velocity correction theoretical plate for different invasion and formation velocities. The calculation is simple and convenient, fast and practical, and suitable for large-scale processing of field data.

[0129] (2) The acoustic velocity correction method proposed by the present invention for horizontal wells fills the gap in the accurate calculation of acoustic wave velocity in horizontal wells. It can automatically calculate and correct by fitting the composite natural logarithm correction formula obtained by the apparent time difference curve of different velocity ratios. When the estimated alteration diameter is input, the ratio of the apparent time difference and the true time difference of the formation can be quickly obtained. Then, the actual measured time difference value, that is, the apparent time difference, can be used to obtain the true time difference of the formation through this ratio. Compared with the traditional method, this method avoids the interpolation processing in the plate and directly calculates through the analytical expression, which is more applicable.

[0130] (3) The true formation time difference (or original formation velocity) obtained by the present invention can be used to calculate the acoustic porosity of the formation, extract the first wave arrival time of the longitudinal wave radial velocity profile, and construct the velocity profile of the acoustic wave remote detection in engineering applications.

[0131] Those skilled in the art can clearly understand that, for the convenience and brevity of description, only the division of the above-mentioned functional units and modules is used as an example for illustration. In actual applications, the above-mentioned functions can be distributed and completed by different functional units and modules as needed, that is, the internal structure of the device can be divided into different functional units or modules to complete all or part of the functions described above. The functional units and modules in the embodiment can be integrated into one processing unit, or each unit can exist physically alone, or two or more units can be integrated into one unit. The above-mentioned integrated unit can be implemented in the form of hardware or in the form of software functional units. In addition, the specific names of the functional units and modules are only for the convenience of distinguishing each other, and are not used to limit the scope of protection of this application. The specific working process of the units and modules in the above-mentioned system can refer to the corresponding process in the aforementioned method embodiment, and will not be repeated here.

[0132] In the above embodiments, the description of each embodiment has its own focus. For parts that are not described or recorded in detail in a certain embodiment, reference can be made to the relevant description of other embodiments.

[0133] Those skilled in the art will appreciate that the units and algorithm steps of each example described in conjunction with the embodiments disclosed in the present invention can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are performed in hardware or software depends on the specific application and design constraints of the technical solution. Professionals and technicians can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of the present invention.

[0134] In the embodiments provided by the present invention, it should be understood that the disclosed devices / terminals and methods can be implemented in other ways. For example, the device / terminal embodiments described above are merely illustrative. For example, the division of the modules or units is merely a logical functional division. In actual implementation, there may be other division methods, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. In addition, the mutual coupling or direct coupling or communication connection shown or discussed can be through some interface, indirect coupling or communication connection of devices or units, and can be electrical, mechanical, or other forms.

[0135] The units described as separate components may or may not be physically separate, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed across multiple network units. Some or all of these units may be selected to achieve the purpose of this embodiment according to actual needs.

[0136] In addition, the functional units in the various embodiments of the present invention may be integrated into a single processing unit, each unit may exist physically separately, or two or more units may be integrated into a single unit. The aforementioned integrated units may be implemented in the form of hardware or software functional units.

[0137] If the integrated module / unit is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the present invention implements all or part of the process in the above-mentioned embodiment method, and can also be completed by instructing the relevant hardware through a computer program. The computer program can be stored in a computer-readable storage medium. When the computer program is executed by a processor, it can implement the steps of the above-mentioned various method embodiments. Among them, the computer program includes computer program code, and the computer program code can be in source code form, object code form, executable file or some intermediate form. The computer-readable medium may include: any entity or device capable of carrying the computer program code, recording medium, USB flash drive, mobile hard disk, magnetic disk, optical disk, computer memory, read-only memory (ROM), random access memory (RAM), electric carrier signal, telecommunication signal and software distribution medium, etc. It should be noted that the content contained in the computer-readable medium can be appropriately increased or decreased according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, computer-readable media do not include electric carrier signals and telecommunication signals.

[0138] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the steps in the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0139] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0140] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0141] The above content is only for explaining the technical idea of ​​the present invention and cannot be used to limit the protection scope of the present invention. Any changes made on the basis of the technical solution in accordance with the technical idea proposed by the present invention shall fall within the protection scope of the claims of the present invention.

Claims

1. A horizontal well acoustic velocity correction method for formation alteration, characterized in that: The following steps are involved: S1. Perform waveform velocity analysis on the monopole acoustic full wave array data to obtain the longitudinal wave apparent time difference of the formation; S2. Based on the P-wave apparent time difference of the formation obtained in step S1, calculate the corresponding apparent time difference under different velocity ratios between the altered formation and the original formation; S3, performing composite natural logarithm fitting on the curves corresponding to the apparent moveout under different velocity ratios obtained in step S2 to obtain fitting curves under different velocity ratios, and obtaining a formation velocity correction chart of the ratio of the alteration radius to the apparent moveout and the true moveout of the formation based on the fitting curves; S4. Determine the formation invasion radius by combining the electrical logging geological data, and calculate the apparent time difference at different depths of the actual formation target interval based on the time-slow correlation method; S5. Substitute the invasion radius of a certain depth position determined in step S4 into the formation velocity correction chart obtained in step S3 to obtain the ratio of the formation apparent time difference to the formation true time difference. Combined with the apparent time difference at the corresponding depth position in step S4, the formation true time difference value at the corresponding depth position is obtained as the acoustic wave time difference of the original formation.

2. The horizontal well acoustic velocity correction method for formation alteration according to claim 1, characterized in that: In step S1, array acoustic logging is performed in the logging depth interval to obtain monopole acoustic full wave array data.

3. The horizontal well acoustic velocity correction method for formation alteration according to claim 2, characterized in that: P-wave apparent time difference of the stratum The calculation is as follows: in, yes The first of the receiving transducer arrays A receiving transducer, is the spacing between transducers, is the time window.

4. The horizontal well acoustic velocity correction method for formation alteration according to claim 1, characterized in that: Step S2 is specifically as follows: Different altered formation radius ranges were set; the velocity ratio between the altered formation and the undisturbed formation was set; the wellbore monopole array waveforms corresponding to different velocity ratios under different altered radii were obtained using three-dimensional finite difference numerical simulation technology, and the apparent time difference corresponding to different velocity ratios between the altered formation and the undisturbed formation was calculated using the time-slow correlation method.

5. The horizontal well acoustic velocity correction method for formation alteration according to claim 4, characterized in that: The velocity ratio of the altered formation to the original formation includes two situations: the velocity of the altered formation is greater than the velocity of the original formation and the velocity of the altered formation is less than the velocity of the original formation.

6. The horizontal well acoustic velocity correction method for formation alteration according to claim 1, characterized in that: In step S3, when the velocity of the altered formation is greater than the velocity of the original formation: in, is the ratio of the apparent time difference to the undisturbed formation time difference, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the formation alteration radius, is the constant coefficient obtained by fitting.

7. The horizontal well acoustic velocity correction method for formation alteration according to claim 1, characterized in that: In step S3, when the velocity of the altered formation is less than the velocity of the original formation: in, is the ratio of the apparent time difference to the undisturbed formation time difference, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the formation alteration radius, is the constant coefficient obtained by fitting.

8. A horizontal well acoustic velocity correction system for formation alteration, characterized in that: include: The data module performs waveform velocity analysis on the monopole acoustic full-wave array data to obtain the longitudinal wave apparent time difference of the formation; The first calculation module calculates the corresponding apparent time difference under different velocity ratios between the altered stratum and the original stratum based on the P-wave apparent time difference of the stratum obtained by the data module; The fitting module performs composite natural logarithm fitting on the curves corresponding to the apparent time difference under different velocity ratios obtained by the calculation module to obtain fitting curves under different velocity ratios. Based on the fitting curves, a formation velocity correction chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained; The second calculation module combines the electrical logging geological data to determine the formation invasion radius and calculates the apparent time difference at different depths of the actual formation target layer using the time-slow correlation method; The correction module substitutes the invasion radius of a certain depth position determined by the second calculation module into the formation velocity correction plate obtained by the fitting module to obtain the ratio of the formation apparent time difference to the formation true time difference. Combined with the apparent time difference at the corresponding depth position of the second calculation module, the formation true time difference value at the corresponding depth position is obtained as the acoustic wave time difference of the original formation.

9. The horizontal well acoustic velocity correction system for formation alteration according to claim 8, characterized in that: The data module obtains the apparent time difference of the longitudinal wave of the formation The details are as follows: in, yes The first of the receiving transducer arrays A receiving transducer, is the spacing between transducers, is the time window.

10. The horizontal well acoustic velocity correction system for formation alteration according to claim 8, characterized in that: The fitting module obtains the fitting curves under different speed ratios, including: When the velocity of the altered formation is greater than the velocity of the original formation: When the velocity of the altered formation is greater than the velocity of the original formation: in, is the ratio of the apparent time difference to the undisturbed formation time difference, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the constant coefficient obtained by fitting, is the formation alteration radius, is the constant coefficient obtained by fitting.

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