Horizontal well sound velocity correction method and system for stratum alteration

Abstract

The invention discloses a horizontal well sound velocity correction method and system for stratum alteration, and the method comprises the steps: carrying out the waveform velocity analysis of monopole sound wave full-wave train array data, and obtaining the longitudinal wave apparent time difference of a stratum; calculating corresponding apparent time differences under the condition of different alteration stratum and undisturbed stratum velocity ratios; performing composite natural logarithm fitting on the curves corresponding to the apparent time difference under the condition of different speed ratios to obtain fitted curves under the different speed ratios, and obtaining a stratum speed correction chart of the alteration radius and the ratio of the apparent time difference to the stratum true time difference according to the fitted curves; the stratum invasion radius is determined by combining electric logging geological data, and apparent time differences of different depth positions of an actual stratum target layer section are calculated according to a time-slow correlation method; and the invasion radius of a certain depth position is substituted into the stratum velocity correction chart, and the true time difference value of the stratum at the corresponding depth position is obtained by combining the apparent time difference of the corresponding depth position and serves as the interval transit time of the undisturbed stratum. The method is simple and convenient in calculation and suitable for mass processing of field data.

Description

Technical Field

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

[0002] With the development of drilling technology, the unique advantages of horizontal wells have been increasingly valued by oilfield companies. In order to give full play to the reservoir potential and improve oil and gas recovery, major oilfields have widely adopted horizontal well drilling methods. However, with the increasing number of horizontal wells, some new problems have been put before interpretation engineers. First, the borehole environment and formation environment in horizontal wells are different from those in vertical wells, and the response characteristics have changed greatly. In vertical wells, the formation model can be assumed to be an isotropic homogeneous body, and the axis of the logging instrument is perpendicular or approximately perpendicular to the horizontal plane of the formation. Whether it is the formation, borehole or mud invasion shape, it is considered to be rotationally symmetrical around the instrument axis. However, for horizontal wells, the instrument axis is no longer perpendicular to the formation surface, and the symmetry of the borehole and mud invasion shape no longer exists. Therefore, it is impossible to directly apply vertical well logging technology to the oil and gas evaluation of horizontal wells. Second, the original interpretation model is no longer applicable to horizontal wells, making it a difficult problem to accurately obtain formation parameters for 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 has changed. The combined influence of factors such as mud invasion and lithology 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 law of acoustic velocity changes and correction methods caused by mud invasion and lithology combinations in horizontal wells has become a key technical issue that must be solved at present.

[0004] At present, in order to solve the problem of well logging sound velocity correction, Lin Weijun et al. (2006) and Wei Zhoutuo et al. (2015) have respectively carried out research on the propagation law of borehole acoustic field response in vertical wells with different formation inclination angles and in inclined wells with stratified formations (Lin Weijun, Wang Xiuming, Zhang Hailan. Research on borehole acoustic field in inclined formations [J]. Chinese Journal of Geophysics, 2006, 49(1): 284-294). The latter established a sound velocity correction method for non-uniform stratified formations and provided a correction chart (Wei Zhoutuo, Chen Xuelian. Analysis of borehole acoustic field in inclined formations and production of sound velocity correction charts [J]. Journal of Acoustics, 2015, 40(3): 9). In 2016, Yang Xin discussed the law of sound velocity variation caused by the combination of high and low velocity formations near the well in his master's thesis, but did not provide a sound velocity correction scheme (Yang Xin. Master's thesis: Research on time difference correction method for acoustic logging in horizontal wells and highly deviated wells [D]. China University of Petroleum (Beijing), 2016). Taking mud invasion as an example, in vertical wells, it is generally believed that under the pressure difference between the mud in the well and the formation, the mud will invade into the permeable formation, and the invasion depth is evenly distributed around the well axis. In horizontal wells, affected by multiple factors such as formation permeability, pressure difference between the mud in the well and the formation, and gravity, the mud invasion profile is no longer a symmetrical profile around the wellbore in a vertical well, but presents an asymmetric invasion profile. As the mud invasion time increases, the invasion radius on one side of the wellbore is greater than the invasion radius on the other side. The mud invasion profile generally has an "elliptical" shape and a "teardrop" shape. Therefore, it is necessary to analyze and correct the influence of the invasion degree on the acoustic velocity, and the same is true for the lithology combination of the formation in the horizontal well. In general, there is no report on a targeted acoustic velocity correction scheme for the problem that the acoustic velocity of the original formation cannot be accurately and reliably obtained due to the differentiation of the acoustic velocity of the formation caused by factors such as mud invasion and lithology combination. Summary of the invention

[0005] The technical problem to be solved by the present invention is to provide a horizontal well sound velocity correction method and system for formation alteration in response to the deficiencies in the above-mentioned prior art. A sound velocity correction model is constructed through numerical simulation, and a correction plate is produced to solve the technical problem of the inability to accurately obtain the original formation velocity due to mud invasion and different lithology combinations, thereby providing a more realistic formation velocity model for subsequent radial velocity profiles and acoustic long-range detection logging.

[0006] The present invention adopts the following technical solutions:

[0007] A method for correcting acoustic velocity of a horizontal well for formation alteration comprises the following steps:

[0008] S1. Perform waveform velocity analysis on the monopole acoustic full wave array data to obtain the longitudinal wave apparent time difference of the formation;

[0009] S2, based on the P-wave apparent time difference of the stratum obtained in step S1, calculating the apparent time difference corresponding to different velocity ratios of the altered stratum and the original stratum;

[0010] S3, performing composite natural logarithm fitting on the curves corresponding to the apparent time difference 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 time difference and the formation true time difference according to the fitting curve;

[0011] S4. Determine the formation invasion radius in combination with the electrical logging geological data, and calculate the apparent time difference at different depths of the actual formation target layer segment according to 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. Combine the apparent time difference at the corresponding depth position in step S4 to obtain the formation true time difference value at the corresponding depth position 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 wave full wave train 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 array of N receiving transducers, 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 are set; the velocity ratio of the altered formation to the original formation is set; the three-dimensional finite difference numerical simulation technology is used to obtain the corresponding wellbore monopole array waveforms under different velocity ratios at different altered radii, and the time-slow correlation method is used to calculate the corresponding apparent time difference under different velocity ratios of the altered formation to the original formation.

[0019] Furthermore, 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.

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

[0021]

[0022] 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.

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

[0024]

[0025] 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.

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

[0027] 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;

[0028] The first calculation module calculates the apparent time difference corresponding to different velocity ratios of the altered strata and the original strata based on the apparent time difference of the longitudinal wave of the strata obtained by the data module;

[0029] 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, and obtains the formation velocity correction chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference according to the fitting curve;

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

[0031] The correction module substitutes the invasion 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 to the formation true time difference, and combines the apparent time difference of the corresponding depth position of the second calculation module to obtain the formation true time difference value at the corresponding depth position as the acoustic wave time difference of the original formation.

[0032] Specifically, the data module obtains the apparent time difference of the longitudinal wave of the formation ρ(s,T) as follows:

[0033]

[0034] Among them, X m (t) is the mth receiving transducer in the array of N receiving transducers, d is the spacing between transducers, [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, by constructing a diagram of the variation law of apparent acoustic wave time difference of different formations, combining data such as invasion radius to obtain the true time difference value of the formation, thereby forming a horizontal well sound velocity correction method for formation alteration, and achieving the purpose of the invention; compared with the traditional technology, according to the established theoretical diagram of sound velocity correction, the original formation velocity under any alteration condition can be conveniently obtained, the calculation is fast and convenient, and it is suitable for large-scale processing of field data; numerical simulation and composite natural logarithm fitting technology are applied to the analysis of curve variation law, avoiding the errors that may be caused by traditional interpolation operation methods, and the calculation results are more accurate; combined with other electrical measurement data, the formation invasion radius is estimated, and the corrected continuous sound velocity data can be obtained by substituting it into the theoretical diagram, so that the data is more portable and has a wider range of applications.

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

[0044] Furthermore, when the altered formation velocity is less than the original formation velocity, the variation curve of the alteration radius and the ratio of the apparent time difference to the formation true time difference for any erosion variable diameter and velocity ratio is obtained, so that the formation velocity correction plate of the ratio of the alteration radius and the apparent time difference to the formation true time difference can be obtained, and automatic calculation and correction can be realized, thus avoiding the 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 to calculate, fast and practical, suitable for large-scale processing of field data, and can provide a key basis for determining the acoustic porosity, accurately extracting the arrival time of the longitudinal wave radial velocity profile, and constructing the velocity profile of acoustic long-range 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 working diagram of the method for correcting the acoustic velocity of a horizontal well for formation alteration according to the present invention;

[0049] Figure 2 The comparison diagrams of the wellbore monopolar waveforms at different alteration radii when the source distance is 1.5m, where (a) is the comparison diagram of the wellbore monopolar 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 1 is a graph showing the relationship between the alteration radius and the 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 the invasion radius and the apparent time difference;

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

[0052] Figure 5 It 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, 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 be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0056] In the description of the present invention, it should be understood that the terms “include” and “comprises” indicate the presence of described features, wholes, steps, operations, elements and / or components, but do not exclude the presence or addition of one or more other features, wholes, steps, operations, elements, components and / or collections thereof.

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

[0058] It should be further understood that the term "and / or" used in the present specification and the appended claims refers to any combination of one or more of the associated listed items and all possible combinations, and includes these combinations. For example, A and / or B can represent: A exists alone, A and B exist at the same time, and B exists alone. In addition, the character " / " in the present invention generally indicates that the associated objects are in an "or" relationship.

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

[0060] The word "if" as used herein may be interpreted as "at the time of" or "when" or "in response to determining" or "in response to detecting", depending on the context. Similarly, the phrases "if it is determined" or "if (stated condition or event) is detected" may be interpreted as "when it is determined" or "in response to determining" or "when detecting (stated condition or event)" or "in response to detecting (stated condition or event)", depending on the context.

[0061] Various structural schematic diagrams of the embodiments disclosed in the present invention are shown in the accompanying drawings. These figures are not drawn to scale, and some details are magnified and some details may be omitted for the purpose of clear expression. The shapes of various regions and layers shown in the figures and the relative sizes and positional relationships therebetween are only exemplary, and may deviate in practice due to manufacturing tolerances or technical limitations, and those skilled in the art may additionally design regions / layers with different shapes, sizes, and relative positions according to actual needs.

[0062] In view of the problem that the formation sound velocity differentiation caused by factors such as mud invasion and lithology combination makes it impossible to accurately and reliably obtain the original formation sound velocity, the present invention provides a horizontal well sound velocity correction method for formation alteration. Through a large number of numerical simulation calculations and theoretical analyses, a theoretical chart for sound velocity correction is obtained, which can conveniently obtain the original formation velocity under any altered diameter conditions. The calculation is simple and convenient, fast and practical, suitable for a large amount of on-site data processing, solves the technical problem of being unable to accurately obtain the original formation sound velocity caused by mud invasion and lithology combination, fills the blank in the related field, realizes automatic calculation and correction, avoids the interpolation processing in the chart, has stronger applicability, and provides a key basis for the determination of acoustic porosity, the accurate extraction of arrival times of longitudinal wave radial velocity profiles, and the construction of velocity profiles for acoustic far detection.

[0063] A horizontal well sound velocity correction method for formation alteration according to the present invention can accurately and quickly obtain the original formation acoustic wave velocity of the formation, and includes the following steps:

[0064] S1. Perform waveform velocity analysis on the obtained monopole acoustic full-wave train array data to obtain the longitudinal wave apparent time difference of the formation;

[0065] The method for obtaining the monopole acoustic full-wave train array data is: perform array acoustic logging in the logging depth interval to obtain the monopole acoustic full-wave train array data;

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

[0067]

[0068] where X m (t) is the m-th receiving transducer in the N-receiver array, and d is the interval between the transducers.

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

[0070] In the numerator part, the waveform data X m (t), (1 < m ≤ N) on each receiver is propagated backward in time, or in other words, the waveform is shifted 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 after time shift processing) are added together;

[0072] Then calculate the absolute value of the sum value, square it, and then calculate its integral over the time window [T, T w .

[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 is superimposed and its value in [T,T w ];

[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 above process is repeated for the waveform in a given period using this time window at a certain time step (in actual operation, T w 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 original strata;

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

[0078] First, different radius ranges of altered strata 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, so as to calculate the P-wave apparent time difference of the formation under all alteration diameter changes and velocity ratios.

[0081] S3, performing composite natural logarithm fitting on the apparent time difference curves of different speed ratios to obtain fitting curves under 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, dimensionless; x is the formation alteration radius, in m; y0=260.827, c=0.01, w=0.94, A=1.815 are the constant coefficients obtained by fitting; π is pi.

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

[0088] S4. Combined with other data such as electrical logging, determine the approximate radius of formation invasion, 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 value into the chart to obtain 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 plate 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 sound 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 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 array of N receiving transducers, d is the spacing between transducers, [T,T w ] is the time window.

[0097] The first calculation module calculates the apparent time difference corresponding to different velocity ratios of the altered strata and the original strata based on the apparent time difference of the longitudinal wave of the strata 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, and obtains the formation velocity correction chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference according to the fitting curve;

[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 determines the formation invasion radius in combination with the electrical logging geological data, and calculates the apparent time difference of different depth positions of the actual formation target layer segment according to 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 chart obtained by the fitting module to obtain the ratio of the formation apparent time difference to the formation true time difference, and combines the apparent time difference of the corresponding depth position of the second calculation module to obtain the formation true time difference value at the corresponding depth position 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 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, and is specifically suitable for loading and executing one or more instructions to implement the corresponding method flow or corresponding function; the processor described in the embodiment of the present invention can be used for the operation of the horizontal well acoustic velocity correction method for formation alteration, including:

[0108] The 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 chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained according to 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 section at different depths is calculated based on the time-slow correlation method; the invasion radius at a certain depth position is substituted into the formation velocity correction chart 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 as the acoustic wave time difference of the original formation.

[0109] In another embodiment of the present invention, the present invention also 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 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, and 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] One or more instructions stored in a computer-readable storage medium may be loaded and executed by a processor to implement the corresponding steps of the horizontal well acoustic velocity correction method for formation alteration in the above embodiment; one or more instructions in the computer-readable storage medium are loaded and executed by the processor as follows:

[0111] The 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 chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference is obtained according to 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 section at different depths is calculated based on the time-slow correlation method; the invasion radius at a certain depth position is substituted into the formation velocity correction chart 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 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, rather than all of the embodiments. The components of the embodiments of the present invention described and shown in the drawings here can usually 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 in 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 a horizontal well acoustic velocity correction method for formation alteration proposed by the present invention.

[0114] S1. Performing waveform velocity analysis on the acquired monopole acoustic wave 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, and the velocity ratio is 1.46:1. The wellbore monopolar waveforms under 19 altered radii and uniformly saturated gas and uniformly saturated water formations are calculated, as shown in Figure 1. 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 P-wave time difference according to step S1. Figure 3The above conclusions and understandings are further confirmed, especially the change limit of the alteration velocity is about 1 wavelength (for example, the formation velocity is 3850m / s, the sound source excitation frequency is 20000Hz, so the maximum value of the wave field can be estimated to be 3850 / 20000=0.1925m); in addition, by analyzing the alteration radius (called the intrusion radius) and the apparent time difference at the bottom of the horizontal well, the two satisfy the composite natural logarithmic relationship (see formula 2), so the intrusion radius and the apparent time difference relationship curve of different velocity ratios can be obtained, which is the theoretical basis for the sound velocity correction chart when the altered formation velocity is greater than the original formation velocity. The process is similar when the altered formation velocity is less than the original formation velocity.

[0119] S2. Calculate the corresponding apparent time difference method under different velocity ratios between altered strata and original 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 the formation velocity perpendicular to the well) to 0.4 m (representing that the formation alteration radius is 0.4 m and the original formation velocity is different from the altered formation velocity). Figure 4 and Figure 5 abscissa;

[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, 2.2:1 respectively. Figure 4 As shown in the figure; when the velocity of the altered formation is less than the velocity 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, 1:2.2 respectively, as shown in the figure. Figure 5 As shown;

[0122] Finally, the three-dimensional finite difference numerical simulation technology is used to obtain the corresponding wellbore monopole array waveforms for different velocity ratios under different alteration radii, such as Figure 6 As shown in FIG. 1 , 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 speed ratios shown are indicated by different marks, which are the ratios of the obtained apparent formation time difference and the original formation true time difference set by the numerical simulation.

[0123] S3, performing composite natural logarithm fitting on the apparent time difference curves of different speed ratios to obtain fitting curves under 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 logarithmic fittings.

[0124] S4. The invasion radius of the formation can be inverted according to the resistivity logging, and the P-wave apparent time difference result of the target layer segment can be calculated according to the time-slow correlation method provided in step S1.

[0125] S5, substituting the chart into the ratio of the apparent formation time difference to the true formation time difference, and obtaining the true formation time difference value; Figure 7 The P-wave time difference correction result of a well is given. It can be seen that there is an obvious difference before and after the 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 of sound velocity correction obtained through a large number of numerical simulation calculations and theoretical analysis. The connotation can be represented by a composite natural logarithm, and automatic calculation and correction can be 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 resistivity logging and other data, thus realizing continuous correction and calculation of the logging profile.

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

[0128] (1) The present invention solves the problem that the original formation sound velocity cannot be accurately obtained due to mud invasion and lithology combination. The method uses finite difference numerical simulation of the sound field without invasion radius and lithology 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 determination 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 with different velocity ratios. When the estimated alteration diameter is input, the ratio of the apparent time difference and the true formation time difference can be quickly obtained. Then, the actual measured time difference value, i.e., the apparent time difference, can be used to obtain the true formation time difference 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 acoustic wave long-range detection in engineering applications.

[0131] The technicians in the relevant field can clearly understand that for the convenience and simplicity of description, only the division of the above-mentioned functional units and modules is used as an example for illustration. In practical applications, the above-mentioned function allocation can be 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 in a processing unit, or each unit can exist physically separately, or two or more units can be integrated in 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, which will not be repeated here.

[0132] In the above embodiments, the description of each embodiment has its own emphasis. For parts that are not described or recorded in detail in a certain embodiment, reference can be made to the relevant descriptions 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. Professional and technical personnel can use different methods to implement the described functions for each specific application, but such implementation should not be considered to be 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 only schematic. For example, the division of the modules or units is only a logical function division. There may be other division methods in actual implementation, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be through some interfaces, indirect coupling or communication connection of devices or units, which can be electrical, mechanical or other forms.

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

[0136] In addition, each functional unit in each embodiment of the present invention may be integrated into one processing unit, or each unit may exist physically separately, or two or more units may be integrated into one unit. The above-mentioned integrated unit may be implemented in the form of hardware or in the form of 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 processes 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, and the computer program can implement the steps of the above-mentioned various method embodiments when executed by the processor. 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, U disk, mobile hard disk, 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 generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0139] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1A process or multiple processes and / or boxes Figure 1 A 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 operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0141] The above contents are 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 stratum obtained in step S1, calculating the apparent time difference corresponding to different velocity ratios of the altered stratum and the original stratum; S3, performing composite natural logarithm fitting on the curves corresponding to the apparent time difference 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 time difference and the formation true time difference according to the fitting curve; S4. Determine the formation invasion radius in combination with the electrical logging geological data, and calculate the apparent time difference at different depths of the actual formation target layer segment according to 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. Combine the apparent time difference at the corresponding depth position in step S4 to obtain the formation true time difference value at the corresponding depth position 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: The apparent time difference of the longitudinal wave of the formation ρ(s,T) is calculated as follows: Among them, X m (t) is the mth receiving transducer in the array of N receiving transducers, d is the spacing between transducers, [T,T w ] 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 are set; the velocity ratio of the altered formation to the original formation is set; the three-dimensional finite difference numerical simulation technology is used to obtain the corresponding wellbore monopole array waveforms under different velocity ratios at different altered radii, and the time-slow correlation method is used to calculate the corresponding apparent time difference under different velocity ratios of the altered formation to the original formation.

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 altered formation velocity is greater than the original formation velocity: 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.

7. The horizontal well acoustic velocity correction method for formation alteration according to claim 1, characterized in that: In step S3, when the altered formation velocity is less than the original formation velocity: 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.

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 apparent time difference corresponding to different velocity ratios of the altered strata and the original strata based on the apparent time difference of the longitudinal wave of the strata 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, and obtains the formation velocity correction chart of the ratio of the alteration radius to the apparent time difference and the formation true time difference according to the fitting curve; The second calculation module determines the formation invasion radius in combination with the electrical logging geological data, and calculates the apparent time difference of different depth positions of the actual formation target layer segment according to 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 chart obtained by the fitting module to obtain the ratio of the formation apparent time difference to the formation true time difference, and combines the apparent time difference of the corresponding depth position of the second calculation module to obtain the formation true time difference value at the corresponding depth position 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 longitudinal waves of the formation ρ(s,T) as follows: Among them, X m (t) is the mth receiving transducer in the array of N receiving transducers, d is the spacing between transducers, [T,T w ] 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: 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.

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