Comprehensive compressibility evaluation method for thin interbed tight reservoir

Abstract

The invention relates to the technical field of thin interbed compressibility evaluation, in particular to a comprehensive compressibility evaluation method for a thin interbed tight reservoir, which comprises the following steps: acquiring original geological parameters and original engineering parameters of a target thin interbed reservoir, and sequentially executing two different types of preset micro-dynamic excitation operations on the target thin interbed reservoir, synchronously acquiring a multi-dimensional response signal generated by the stratum under each excitation operation; for each type of excitation operation, based on the corresponding multi-dimensional response signal, determining a conduction mode sequence of the event signal under the type of excitation in the longitudinal direction; conducting mode sequences determined by all types of excitation operations are fused and analyzed, and a dynamic coupling strength index and a stress interference mode between thin interlayers are determined; by analyzing conduction behaviors of the dynamic response signals, real controlled factors of stress wave propagation and fluid pressure transmission in the fracturing process can be directly reflected, and the pertinence and accuracy of evaluation are improved.

Description

Technical Field

[0001] This invention relates to the field of thin interbedded layer compressibility assessment technology, and specifically to a comprehensive compressibility assessment method for thin interbedded tight reservoirs. Background Technology

[0002] Thin interbedded tight reservoirs are important carriers of unconventional oil and gas resources. Their effective development depends heavily on successful hydraulic fracturing. However, thin interbedded reservoirs are composed of multiple thin sand layers and interlayers such as mudstone and siltstone, which frequently alternate and exhibit vertical heterogeneity. This structure leads to high uncertainty in the extension of hydraulic fractures. Fractures may be confined to a single thin layer and fail to form an effective fracture height. They may also undergo unexpected turning or premature fracture arrest at weak surfaces. Furthermore, complex fracture networks may form due to complex stress interference.

[0003] Currently, conventional compressibility assessment methods mainly rely on two types of technical means. One is the calculation of static parameters based on measurement data and core experiments, such as using sonic logging and density logging to calculate rock mechanical parameters and combining them with empirical models such as the brittleness index for evaluation. The other is stress field simulation based on seismic or geomechanical modeling to predict the direction of fracture propagation. These methods have significant limitations when applied to thin interbedded layers. Static parameters cannot reflect the dynamic stress transmission and fluid coupling between thin interbedded layers. Furthermore, models based on homogeneous or simple layered assumptions cannot effectively describe the complex dynamic responses such as stress wave scattering and fluid seepage barriers caused by frequent interfaces in thin interbedded layers. Summary of the Invention

[0004] This invention addresses the technical problems existing in the prior art by providing a comprehensive compressibility assessment method for thin interbedded tight reservoirs.

[0005] The technical solution of this invention to solve the above-mentioned technical problems is as follows: A comprehensive compressibility assessment method for thin interbedded tight reservoirs, comprising the following steps: S1. Obtain the original geological parameters and original engineering parameters of the target thin interbedded reservoir. For the target thin interbedded reservoir, perform two different types of preset micro-dynamic excitation operations in sequence, and simultaneously obtain the multi-dimensional response signals generated by the formation under each excitation operation. S2. For each type of excitation operation, based on its corresponding multi-dimensional response signal, determine the longitudinal transmission mode sequence of the event signal under that type of excitation; S3. By integrating and analyzing the conduction mode sequences determined by all types of excitation operations, the dynamic coupling strength index and stress disturbance mode between thin interlayers are determined. S4. Based on the dynamic coupling strength index and conduction mode, determine the comprehensive compressibility level of the target thin interbedded reservoir.

[0006] In a preferred embodiment, in S1, the original geological parameters are parameters reflecting reservoir properties obtained through well logging and core analysis, including the mineral composition and content of the target thin interbedded reservoir, porosity and permeability distribution, bedding and fracture development, thickness of each single layer and information on interface lithology combination. The original engineering parameters include wellbore structural integrity, initial reservoir pressure and temperature, geological fluid properties and in-situ stress field characteristics. The two different types of preset micro-dynamic excitation operations include a first type of thermoelastic excitation operation and a second type of micro-permeability excitation operation. The first type of thermoelastic excitation operation is to induce the reservoir rock to generate thermoelastic micro-strain waves by circulating and injecting a fluid with a first preset temperature characteristic into the wellbore connected to the target protective reservoir. The second type of micro-permeability induction operation is to apply a second preset periodic pressure pulse to the wellbore of the target thin inter-reservoir to induce low-velocity micro-permeability of the reservoir fluid. During the execution of the first type of thermoelastic excitation operation and the second type of micro-permeability excitation operation, multi-dimensional response signals generated by the formation are collected simultaneously. The multi-dimensional response signals include the three-dimensional strain field change signal of the wellbore obtained by the strain sensor array arranged on the well wall, the micro-vibration signal around the well obtained by the accelerometer, and the wellbore fluid acoustic characteristic evolution signal obtained by the ultrasonic monitoring equipment. In a preferred embodiment, in step S2, curves showing the continuous variation of three key characteristic parameters with measurement depth are extracted from the multidimensional response signal, including the signal strength attenuation rate curve, the signal frequency component variation coefficient curve, and the signal arrival time difference curve. The change curve is smoothed by using a moving average method to eliminate small fluctuations caused by measurement noise and obtain a smooth curve that reflects the overall trend. Based on the smoothed curve, the difference between the value at each depth point and the value at the previous depth point is determined in the order of depth and used as the instantaneous change at that point. Meanwhile, a local window containing a number of adjacent data points is selected near each depth point. Based on the distribution trend of the data points in the window, a linear direction parameter representing the rate of change is determined as the local slope estimate at that point. Simultaneously, two feature sequences representing numerical abrupt changes and slope abrupt changes are obtained. The judgment threshold is set based on the distribution of the feature sequence generated by the curve. For numerical mutation sequences, the absolute value is taken to form a new sequence. The statistical distribution characteristics of the sequence are analyzed, and a boundary value for judging numerical mutation is determined from it. This value is used as the numerical mutation threshold. For slope mutation sequences, the statistical distribution characteristics are analyzed, and a boundary value for judging slope mutation is determined from it. This value is used as the slope mutation threshold. Scan each depth point. If the absolute value of its instantaneous change exceeds the numerical mutation threshold, the depth point is initially marked as a candidate mutation point. Check whether there are continuous abnormal changes near each candidate mutation point. If several adjacent depth points also show as candidate mutation points, it is confirmed that there is a mutation in the region. At the same time, multiple candidate mutation points with too close depth distances are merged into a single mutation point representing the mutation region. By matching and correlating single mutation points with the geological layer interface depths between thin interbedded layers, and by corresponding physical signal anomaly locations with specific geological lithological interfaces, the critical impedance interfaces are determined. Based on the calibrated critical impedance interface, the coordinated attenuation and variation of the three characteristic parameters of signal intensity, frequency and time difference in each well section are analyzed. If the signal attenuation is slow, the frequency is stable and the time difference changes gently, then the well section is classified as a free conduction mode, which represents the formation mean and has little obstruction to signal propagation. If the signal decays rapidly, the frequency undergoes selective filtering, and the time difference increases, then the well section is classified as an attenuation lag mode, which indicates that the formation has a strong absorption and scattering effect on the signal. If the signal attenuation is irregular, the frequency components are disordered, and the time difference fluctuates drastically, it is classified as a scattering disorder mode, which indicates that the formation structure is highly heterogeneous and contains a large number of cracks and pores.

[0007] In a preferred embodiment, in S3, if the geological interface between thin interlayers is determined to be a free conduction mode under both the first type of thermoelastic excitation and the second type of micro-seepage excitation, it indicates that the region has dual characteristics and is determined to be a strong dynamic coupling zone. Its free conduction to thermoelastic excitation indicates that the rock skeleton is intact and elastic, the intralayer interface is firmly cemented, and stress waves can pass through with low loss. Its free conduction to micro-seepage disturbance indicates that the seepage channel is unobstructed, the network connectivity of pores and fractures is good, and the fluid pressure can be effectively transmitted. If the geological interface between thin interlayers allows free conduction of thermoelastic excitation but inhibits micro-seepage excitation, it indicates that the rock mechanical structure is intact, but there is a seepage barrier in the seepage channel, and it is then identified as a selective coupling zone. If a geological interface between thin interlayers exhibits a non-free conduction mode for both thermoelastic excitation and micro-permeation excitation, it indicates that the geological interface has internal heterogeneity and deterioration in both its mechanical structure and permeation network, and is therefore identified as a weak dynamic coupling zone.

[0008] In a preferred embodiment, in step S4, a basic compressibility potential level is established based on the dynamic coupling strength index, wherein a strong dynamic coupling zone corresponds to a high potential level, a selective coupling zone corresponds to a medium potential level, and a weak dynamic coupling zone corresponds to a low potential level. The basic compressibility potential level is corrected based on the spatial distribution of the conduction modes. For the strong dynamic coupling zone and the basic level of high potential, if the conduction mode is the attenuation retardation mode, the compressibility rating is downgraded to medium compressibility. If the conduction mode is the scattering disorder mode, the compressibility rating is downgraded to low compressibility. For the selective coupling zone and the weak dynamic coupling zone, the upper limit of the compressibility rating is determined according to the proportion of the attenuation retardation mode and the scattering disorder mode in the well section, so as to obtain the corrected compressibility rating of the whole well section. The corrected compressibility rating data sequence of the entire well section is traversed in ascending order of depth. Starting from the first depth sampling point, the scan identifies and records all continuous depth intervals rated as high compressibility. When a depth sampling point is rated as high compressibility and its next adjacent depth sampling point is also rated as high compressibility, these points are considered as part of the same continuous segment until a depth point where the rating changes is encountered, at which point the recording of the continuous segment ends. For each identified high compressibility continuous segment, its starting depth value and ending depth value are extracted. The difference between the ending depth value and the starting depth value is the continuous depth span of the segment. The calculated depth span is directly used as the average thickness of the segment. Based on the preset continuity and thickness threshold, it is divided into the main fracture advantageous segment that is conducive to the formation of the main fracture and the main fracture potential limited segment with limited potential. Simultaneously, the alternation pattern of low compressibility zone and risk zone in the longitudinal direction is identified. If the difference in compressibility rating on both sides of a critical impedance interface exceeds a preset threshold, the interface is determined to be an interface that hinders the longitudinal extension of the crack. If a critical impedance interface is located in the selective coupling region and its extension exceeds a preset length, then the interface is determined to be a channel through which fracturing fluid may flow laterally. The results of the comprehensive assessment of the main fracture formation potential, stress disturbance pattern identification, and distribution analysis of natural barriers and channels are used to generate a comprehensive compressibility evaluation that classifies the target reservoir into high, medium, and low compressibility.

[0009] The beneficial effects of this invention are as follows: By performing thermoelastic excitation and micro-permeability excitation, which correspond to the mechanical response of the rock skeleton and the permeability response of pore fluid respectively, this invention directly excites the micro-response of the reservoir under the core physical mechanism of fracturing. By analyzing the transmission behavior of these dynamic response signals, the dynamic coupling strength index and stress interference mode are determined, which can directly reflect the real controlled factors of stress wave propagation and fluid pressure transmission during fracturing, thus improving the pertinence and accuracy of the assessment. Attached Figure Description

[0010] Figure 1 This is a flowchart of the present invention. Detailed Implementation

[0011] The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0012] In the description of this application, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of indicated technical features. Thus, a feature defined as "first" or "second" may explicitly or implicitly include one or more of the stated features. In the description of this application, "multiple" means two or more, unless otherwise explicitly specified.

[0013] In the description of this application, the term "for example" is used to mean "used as an example, illustration, or description." Any embodiment described as "for example" in this application is not necessarily to be construed as being more preferred or advantageous than other embodiments. The following description is provided to enable any person skilled in the art to make and use the invention. Details are set forth in the following description for purposes of explanation. It should be understood that those skilled in the art will recognize that the invention can be made without using these specific details. In other instances, well-known structures and processes will not be described in detail to avoid obscuring the description of the invention with unnecessary detail. Therefore, the invention is not intended to be limited to the embodiments shown, but is consistent with the broadest scope of the principles and features disclosed in this application.

[0014] like Figure 1 This embodiment provides a comprehensive compressibility assessment method for thin interbedded tight reservoirs, comprising the following steps: S1. Obtain the original geological parameters and original engineering parameters of the target thin interbedded reservoir. For the target thin interbedded reservoir, perform two different types of preset micro-dynamic excitation operations in sequence, and simultaneously obtain the multi-dimensional response signals generated by the formation under each excitation operation. Furthermore, the original geological parameters, which are obtained through well logging and core analysis and reflect reservoir properties, include the mineral composition and content of the target thin interbedded reservoir, porosity and permeability distribution, bedding and fracture development, thickness of each single layer and information on interface lithology. The original engineering parameters include wellbore structural integrity, initial reservoir pressure and temperature, geological fluid properties and in-situ stress field characteristics. The two different types of preset micro-dynamic excitation operations include a first type of thermoelastic excitation operation and a second type of micro-permeability excitation operation. The first type of thermoelastic excitation operation is to induce the reservoir rock to generate thermoelastic micro-strain waves by circulating and injecting a fluid with a first preset temperature characteristic into the wellbore connected to the target protective reservoir. The second type of micro-permeability induction operation is to apply a second preset periodic pressure pulse to the wellbore of the target thin inter-reservoir to induce low-velocity micro-permeability of the reservoir fluid. During the execution of the first type of thermoelastic excitation operation and the second type of micro-permeability excitation operation, multi-dimensional response signals generated by the formation are collected simultaneously. The multi-dimensional response signals include the three-dimensional strain field change signal of the wellbore obtained by the strain sensor array arranged on the well wall, the micro-vibration signal around the well obtained by the accelerometer, and the wellbore fluid acoustic characteristic evolution signal obtained by the ultrasonic monitoring equipment. It should be noted that the first preset temperature characteristic is based on the thermophysical properties of the rock, including the thermal expansion coefficient, thermal conductivity and specific heat capacity of the rock, to calculate the thermoelastic micro-strain wave that can be detected in the reservoir rock. The second preset periodic pressure pulse is derived by combining the formation fluid properties (such as viscosity and compressibility) with the pore structure characteristics (such as permeability and porosity) to derive the starting pressure gradient and pressure disturbance frequency range required to induce low-speed micro-seepage of the formation fluid.

[0015] S2. For each type of excitation operation, based on its corresponding multi-dimensional response signal, determine the longitudinal transmission mode sequence of the event signal under that type of excitation; Furthermore, curves showing the continuous variation of three key characteristic parameters with measurement depth are extracted from the multidimensional response signal, including the signal strength attenuation rate curve, the signal frequency component variation coefficient curve, and the signal arrival time difference curve. The signal strength attenuation rate curve is used to characterize how fast the signal energy is lost during propagation in the stratum; the signal frequency component variation coefficient curve is used to reflect the relative change in the signal spectrum structure during propagation; and the signal arrival time difference curve is used to indicate the longitudinal difference in signal propagation speed. The change curve is smoothed by using a moving average method to eliminate small fluctuations caused by measurement noise and obtain a smooth curve that reflects the overall trend. Based on the smoothed curve, the difference between the value at each depth point and the value at the previous depth point is determined in the order of depth and used as the instantaneous change at that point. It should be noted that a depth point is a specific location where a measurement or sampling is performed in the vertical direction. Each depth point corresponds to a known and unique depth value and is associated with physical signal data collected by a sensor at that location. Meanwhile, a local window containing a number of adjacent data points is selected near each depth point. Based on the distribution trend of the data points in the window, a linear direction parameter representing the rate of change is determined as the local slope estimate at that point. Simultaneously, two feature sequences representing numerical abrupt changes and slope abrupt changes are obtained. The judgment threshold is set based on the distribution of the feature sequence generated by the curve. For numerical mutation sequences, the absolute value is taken to form a new sequence. The statistical distribution characteristics of the sequence are analyzed, and a boundary value for judging numerical mutation is determined from it. This value is used as the numerical mutation threshold. For slope mutation sequences, the statistical distribution characteristics are analyzed, and a boundary value for judging slope mutation is determined from it. This value is used as the slope mutation threshold. The determination of the threshold value is to enable it to adapt to the fluctuation level of the curve itself. Specifically, this is achieved by selecting the value at a specific relative position from each sequence after sorting them by numerical size as the threshold benchmark. Scan each depth point. If the absolute value of its instantaneous change exceeds the numerical mutation threshold, the depth point is initially marked as a candidate mutation point. Check whether there are continuous abnormal changes near each candidate mutation point. If several adjacent depth points also show as candidate mutation points, it is confirmed that there is a mutation in the region. At the same time, multiple candidate mutation points with too close depth distances are merged into a single mutation point representing the mutation region. By matching and correlating single mutation points with the geological layer interface depths between thin interbedded layers, and by corresponding physical signal anomaly locations with specific geological lithological interfaces, the critical impedance interfaces are determined. Based on the calibrated critical impedance interface, the coordinated attenuation and variation of the three characteristic parameters of signal intensity, frequency and time difference in each well section are analyzed. If the signal attenuation is slow, the frequency is stable and the time difference changes gently, then the well section is classified as a free conduction mode, which represents the formation mean and has little obstruction to signal propagation. If the signal decays rapidly, the frequency undergoes selective filtering, and the time difference increases, then the well section is classified as an attenuation lag mode, which indicates that the formation has a strong absorption and scattering effect on the signal. If the signal attenuation is irregular, the frequency components are disordered, and the time difference fluctuates drastically, it is classified as a scattering disorder mode, which indicates that the formation structure is highly heterogeneous and contains a large number of cracks and pores.

[0016] S3. By integrating and analyzing the conduction mode sequences determined by all types of excitation operations, the dynamic coupling strength index and stress disturbance mode between thin interlayers are determined. Furthermore, if the geological interface between thin interlayers is determined to be a free conduction mode under both the first type of thermoelastic excitation and the second type of micro-seepage excitation, it indicates that the region has dual characteristics and is identified as a strong dynamic coupling zone. Its free conduction to thermoelastic excitation indicates that the rock skeleton is intact and elastic, the intralayer interface is firmly cemented, and stress waves can pass through with low loss. Its free conduction to micro-seepage disturbance indicates that the seepage channels are unobstructed, the network connectivity of pores and fractures is good, and the fluid pressure can be effectively transmitted. If the geological interface between thin interlayers allows free conduction of thermoelastic excitation but inhibits micro-seepage excitation, it indicates that the rock mechanical structure is intact, but there is a seepage barrier in the seepage channel, and it is then identified as a selective coupling zone. If a geological interface between thin interlayers exhibits a non-free conduction mode for both thermoelastic excitation and micro-permeation excitation, it indicates that the geological interface has internal heterogeneity and deterioration in both its mechanical structure and permeation network, and is therefore identified as a weak dynamic coupling zone.

[0017] S4. Based on the dynamic coupling strength index and conduction mode, determine the comprehensive compressibility level of the target thin interbedded reservoir.

[0018] Furthermore, a basic compressibility potential level is established based on the dynamic coupling strength index, where the strong dynamic coupling zone corresponds to the high potential level, the selective coupling zone corresponds to the medium potential level, and the weak dynamic coupling zone corresponds to the low potential level. The basic compressibility potential level is corrected based on the spatial distribution of the conduction modes. For the strong dynamic coupling zone and the basic level of high potential, if the conduction mode is the attenuation retardation mode, the compressibility rating is downgraded to medium compressibility. If the conduction mode is the scattering disorder mode, the compressibility rating is downgraded to low compressibility. For the selective coupling zone and the weak dynamic coupling zone, the upper limit of the compressibility rating is determined according to the proportion of the attenuation retardation mode and the scattering disorder mode in the well section, so as to obtain the corrected compressibility rating of the whole well section. The corrected compressibility rating data sequence of the entire well section is traversed in ascending order of depth. Starting from the first depth sampling point, the scan identifies and records all continuous depth intervals rated as high compressibility. When a depth sampling point is rated as high compressibility and its next adjacent depth sampling point is also rated as high compressibility, these points are considered as part of the same continuous segment until a depth point where the rating changes is encountered, at which point the recording of the continuous segment ends. For each identified high compressibility continuous segment, its starting depth value and ending depth value are extracted. The difference between the ending depth value and the starting depth value is the continuous depth span of the segment. The calculated depth span is directly used as the average thickness of the segment. Based on the preset continuity and thickness threshold, it is divided into the main fracture advantageous segment that is conducive to the formation of the main fracture and the main fracture potential limited segment with limited potential. It should be noted that the preset continuity and thickness thresholds are extracted from the regional geological database of developed reservoirs with similar sedimentary genesis and lithological combinations to the target reservoir. The vertical continuity distribution characteristics of the high-quality reservoirs are statistically analyzed, and the depth span data of the high-quality reservoirs are analyzed. The low quantile value of its statistical distribution is used as a reference for the initial continuity value. At the same time, the thickness data of the high-quality reservoirs are statistically analyzed, and the low quantile value of its statistical distribution is used as a reference for the initial thickness value. This value reflects the basic thickness scale required for the formation of industrially valuable reservoirs in the region.

[0019] Simultaneously, the alternation pattern of low compressibility zone and risk zone in the longitudinal direction is identified. If the difference in compressibility rating on both sides of a critical impedance interface exceeds a preset threshold, the interface is determined to be an interface that hinders the longitudinal extension of the crack. If a critical impedance interface is located in the selective coupling region and its extension exceeds a preset length, then the interface is determined to be a channel through which fracturing fluid may flow laterally. The results of the comprehensive assessment of the main fracture formation potential, stress disturbance pattern identification, and distribution analysis of natural barriers and channels are used to generate a comprehensive compressibility evaluation that classifies the target reservoir into high, medium, and low compressibility.

[0020] It should be noted that the preset threshold refers to the compressibility rating quantitative index for determining whether the critical impedance interface is a barrier to fracture propagation. This threshold is comprehensively calibrated by inverting the correspondence between fracture monitoring data and compressibility profiles of historical fractured wells, and by combining numerical simulation to verify the critical impact of rating differences on fracture probability. The preset length refers to the minimum spatial continuity scale requirement that must be met to determine whether the critical impedance interface can become an effective channel for flow. This length is comprehensively determined based on the geological statistical characteristics of the target reservoir and the design requirements of the fracturing project.

[0021] It should be noted that the descriptions of each embodiment in the above embodiments have different focuses. For parts that are not described in detail in a certain embodiment, please refer to the relevant descriptions in other embodiments.

[0022] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0023] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded computer, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0024] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0025] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0026] Although preferred embodiments of the invention have been described, those skilled in the art, upon learning the basic inventive concept, can make other changes and modifications to these embodiments. Therefore, the appended claims are intended to be interpreted as including both the preferred embodiments and all changes and modifications falling within the scope of the invention.

[0027] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A comprehensive compressibility assessment method for thin interbedded tight reservoirs, characterized in that, Includes the following steps: S1. Obtain the original geological parameters and original engineering parameters of the target thin interbedded reservoir. For the target thin interbedded reservoir, perform two different types of preset micro-dynamic excitation operations in sequence, and simultaneously obtain the multi-dimensional response signals generated by the formation under each excitation operation. S2. For each type of excitation operation, based on its corresponding multi-dimensional response signal, determine the longitudinal transmission mode sequence of the event signal under that type of excitation; S3. By integrating and analyzing the conduction mode sequences determined by all types of excitation operations, the dynamic coupling strength index and stress disturbance mode between thin interlayers are determined. S4. Based on the dynamic coupling strength index and conduction mode, determine the comprehensive compressibility level of the target thin interbedded reservoir.

2. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 1, characterized in that, In S1, the original geological parameters are parameters that reflect reservoir properties obtained through well logging and core analysis, including the mineral composition and content of the target thin interbedded reservoir, porosity and permeability distribution, bedding and fracture development, thickness of each single layer and information on interface lithology combination. The original engineering parameters include wellbore structural integrity, initial reservoir pressure and temperature, geological fluid properties and in-situ stress field characteristics. The two different types of preset micro-dynamic excitation operations include a first type of thermoelastic excitation operation and a second type of micro-permeability excitation operation. The first type of thermoelastic excitation operation is to induce the reservoir rock to generate thermoelastic micro-strain waves by circulating and injecting a fluid with a first preset temperature characteristic into the wellbore connected to the target protective reservoir. The second type of micro-permeability induction operation is to apply a second preset periodic pressure pulse to the wellbore of the target thin interconnected reservoir to induce low-velocity micro-permeability of the reservoir fluid.

3. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 2, characterized in that, During the execution of the first type of thermoelastic excitation operation and the second type of micro-permeability excitation operation, multi-dimensional response signals generated by the formation are collected simultaneously. These multi-dimensional response signals include the three-dimensional strain field change signal of the wellbore obtained by the strain sensor array arranged on the well wall, the micro-vibration signal around the well obtained by the accelerometer, and the evolution signal of the wellbore fluid acoustic characteristics obtained by the ultrasonic monitoring equipment.

4. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 1, characterized in that, In S2, three key feature parameters are extracted from the multidimensional response signal as curves showing continuous changes with measurement depth, including the signal strength attenuation rate curve, the signal frequency component variation coefficient curve, and the signal arrival time difference curve. The change curve is smoothed by using a moving average method to eliminate small fluctuations caused by measurement noise and obtain a smooth curve that reflects the overall trend. Based on the smoothed curve, the difference between the value at each depth point and the value at the previous depth point is determined in the order of depth and used as the instantaneous change at that point. Meanwhile, a local window containing a number of adjacent data points is selected near each depth point. Based on the distribution trend of the data points within the window, a linear direction parameter representing the rate of change is determined as the local slope estimate at that point. Simultaneously, two feature sequences representing numerical abrupt changes and slope abrupt changes are obtained.

5. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 4, characterized in that, The judgment threshold is set based on the distribution of the feature sequence generated by the curve. For numerical mutation sequences, the absolute value is taken to form a new sequence. The statistical distribution characteristics of the sequence are analyzed, and a boundary value for judging numerical mutation is determined from it. This value is used as the numerical mutation threshold. For slope mutation sequences, the statistical distribution characteristics are analyzed, and a boundary value for judging slope mutation is determined from it. This value is used as the slope mutation threshold. Scan each depth point. If the absolute value of its instantaneous change exceeds the numerical mutation threshold, the depth point is initially marked as a candidate mutation point. Check whether there are continuous abnormal changes near each candidate mutation point. If several adjacent depth points also show as candidate mutation points, it is confirmed that there is a mutation in the region. At the same time, multiple candidate mutation points with too close depth distances are merged into a single mutation point representing the mutation region.

6. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 5, characterized in that, By matching and correlating single mutation points with the geological layer interface depths between thin interbedded layers, and by corresponding physical signal anomaly locations with specific geological lithological interfaces, the key impedance interfaces are determined. Based on the calibrated critical impedance interface, the coordinated attenuation and variation of the three characteristic parameters of signal intensity, frequency and time difference in each well section are analyzed. If the signal attenuation is slow, the frequency is stable and the time difference changes gently, then the well section is classified as a free conduction mode, which represents the formation mean and has little obstruction to signal propagation. If the signal decays rapidly, the frequency undergoes selective filtering, and the time difference increases, then the well section is classified as an attenuation lag mode, which indicates that the formation has a strong absorption and scattering effect on the signal. If the signal attenuation is irregular, the frequency components are disordered, and the time difference fluctuates drastically, it is classified as a scattering disorder mode, which indicates that the formation structure is highly heterogeneous and contains cracks and pores.

7. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 1, characterized in that, In S3, if the geological interface between thin interlayers is determined to be a free conduction mode under both the first type of thermoelastic excitation and the second type of micro-seepage excitation, it indicates that the region has dual characteristics and is determined to be a strong dynamic coupling zone. Its free conduction to thermoelastic excitation indicates that the rock skeleton is intact and elastic, the intralayer interface is firmly cemented, and stress waves can pass through with low loss. Its free conduction to micro-seepage disturbance indicates that the seepage channel is unobstructed, the network connectivity of pores and fractures is good, and the fluid pressure can be effectively transmitted. If the geological interface between thin interlayers allows free conduction of thermoelastic excitation but inhibits micro-seepage excitation, it indicates that the rock mechanical structure is intact, but there is a seepage barrier in the seepage channel, and it is then identified as a selective coupling zone. If a geological interface between thin interlayers exhibits a non-free conduction mode for both thermoelastic excitation and micro-permeation excitation, it indicates that the geological interface has internal heterogeneity and deterioration in both its mechanical structure and permeation network, and is therefore identified as a weak dynamic coupling zone.

8. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 1, characterized in that, In S4, a basic compressibility potential level is established based on the dynamic coupling strength index, wherein a strong dynamic coupling zone corresponds to a high potential level, a selective coupling zone corresponds to a medium potential level, and a weak dynamic coupling zone corresponds to a low potential level. The basic compressibility potential level is corrected based on the spatial distribution of the conduction modes. For the strong dynamic coupling zone and the basic level of high potential, if the conduction mode is the attenuation retardation mode, the compressibility rating is downgraded to medium compressibility. If the conduction mode is the scattering disorder mode, the compressibility rating is downgraded to low compressibility. For the selective coupling zone and the weak dynamic coupling zone, the upper limit of the compressibility rating is determined according to the proportion of the attenuation retardation mode and the scattering disorder mode in the well section, so as to obtain the corrected compressibility rating of the whole well section.

9. The comprehensive compressibility assessment method for thin interbedded tight reservoirs according to claim 8, characterized in that, The corrected compressibility rating data sequence of the entire well section is traversed in ascending order of depth. Starting from the first depth sampling point, the scan identifies and records all continuous depth intervals rated as high compressibility. When a depth sampling point is rated as high compressibility and its next adjacent depth sampling point is also rated as high compressibility, these points are considered as part of the same continuous segment until a depth point where the rating changes is encountered, at which point the recording of the continuous segment ends. For each identified high compressibility continuous segment, its starting depth value and ending depth value are extracted. The difference between the ending depth value and the starting depth value is the continuous depth span of the segment. The calculated depth span is directly used as the average thickness of the segment. Based on the preset continuity and thickness threshold, it is divided into the main fracture advantageous segment that is conducive to the formation of the main fracture and the main fracture potential limited segment with limited potential. Simultaneously, the alternation pattern of low compressibility zone and risk zone in the longitudinal direction is identified. If the difference in compressibility rating on both sides of a critical impedance interface exceeds a preset threshold, the interface is determined to be an interface that hinders the longitudinal extension of the crack. If a critical impedance interface is located in the selective coupling region and its extension exceeds a preset length, then the interface is determined to be a channel through which fracturing fluid may flow laterally. The results of the comprehensive assessment of the main fracture formation potential, stress disturbance pattern identification, and distribution analysis of natural barriers and channels are used to generate a comprehensive compressibility evaluation that classifies the target reservoir into high, medium, and low compressibility.

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