Method, apparatus and medium for determining shale pore fluid type and porosity

Abstract

The application provides a shale pore fluid type and porosity determination method, device and medium. The method obtains nuclear magnetic resonance logging data of shale in a target interval, performs T2 spectrum component stripping processing on the data, obtains a plurality of corresponding nuclear magnetic resonance logging T2 sub-spectra, determines pore fluid type calibration characteristics according to differences in T1-T2 spectrum diagrams of shale with different clay mineral contents and under different core saturation states, calibrates the fluid type of the plurality of nuclear magnetic resonance logging T2 sub-spectra based on the pore fluid type calibration characteristics, obtains the fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, and then determines the effective porosity and movable fluid porosity of the shale based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid type. The method improves the calculation accuracy of the porosity, and provides a simple and reliable method for fluid type discrimination and porosity calculation of logging that only measures one-dimensional nuclear magnetic resonance logging and has no coring nuclear magnetic resonance experiment.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas exploration, and particularly relates to a shale pore fluid type and porosity determination method, device and medium. BACKGROUND

[0002] As a typical unconventional reservoir, shale has the characteristics of fine-grained polymictic mineral accumulation and complex micro-nanopore structure. The quality evaluation and efficient development of shale oil reservoirs largely depend on the accurate characterization of the fluid mobility in shale pores. The oil and gas accumulation process of shale is a self-generation and self-storage mode of organic matter, which is significantly different from the buoyancy-driven conventional reservoir. This particularity leads to more complex fluid types and spatial distribution in shale pores, and it is difficult to finely characterize them. The pore space that can store oil and gas in shale reservoirs is all effective pores, that is, the effective porosity excludes only the portion occupied by clay bound water. Therefore, accurate calculation of the effective porosity of shale is crucial for reservoir evaluation.

[0003] At present, the commonly used method for determining the effective porosity of shale in the prior art usually includes core experiment analysis method and logging T2 cutoff value method.

[0004] The core experiment analysis method mainly uses a two-dimensional nuclear magnetic resonance core analyzer to measure core samples, and realizes fluid discrimination and porosity calculation by establishing a T1-T2 fluid type identification chart. However, due to the high cost of downhole shale coring and laboratory measurement, it is difficult to realize longitudinal continuous characterization; and the magnetic field strength, frequency and other parameters of different instruments have not been unified, so that the detection results are difficult to be directly calibrated and applied to nuclear magnetic resonance logging data analysis.

[0005] The logging T2 cutoff value method is based on the difference in T2 relaxation time distribution of different pore fluids, and divides the fluid interval by setting T2 cutoff value (T 2cutoff ), and calculates the corresponding porosity by integral method. However, neither the fixed T2 cutoff value method nor the variable T2 cutoff value method fully considers the complex pore structure and fluid distribution characteristics of shale. In addition, abnormal noise interference in the logging process leads to large error in porosity calculation, which seriously affects the accuracy of shale reservoir quality evaluation. SUMMARY

[0006] The embodiments of the present application provide a shale pore fluid type and porosity determination method, device and medium, to solve the problems that the shale pore fluid type is difficult to divide and the effective porosity calculation accuracy is low in the prior art.

[0007] In a first aspect, the present application provides a shale pore fluid type and porosity determination method, which comprises:

[0008] Obtaining nuclear magnetic resonance logging data of shale in a target interval, and performing T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra corresponding thereto;

[0009] Performing fluid type calibration on the plurality of nuclear magnetic resonance logging T2 sub-spectra by using a pore fluid type calibration feature to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, wherein the pore fluid type calibration feature is used to indicate a T1-T2 signal interval distribution corresponding to a plurality of pore fluid types, and the pore fluid type calibration feature is determined according to differences in T1-T2 spectrum diagrams under different clay mineral content shale and different core saturation states;

[0010] Based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid types, determining the effective porosity and movable fluid porosity of the shale.

[0011] In a possible implementation, the T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra corresponding thereto includes:

[0012] Performing component analysis on the nuclear magnetic resonance logging data by using independent component analysis technology to obtain a T2 spectrum signal matrix corresponding thereto;

[0013] Performing multi-component signal and peak spectrum sorting processing on the T2 spectrum signal matrix based on sparse non-negative matrix factorization technology to obtain a plurality of candidate nuclear magnetic resonance logging T2 sub-spectra;

[0014] Stripping abnormal noise spectrum from the plurality of candidate nuclear magnetic resonance logging T2 sub-spectra to obtain the plurality of nuclear magnetic resonance logging T2 sub-spectra.

[0015] In a possible implementation, before the fluid type calibration on the plurality of nuclear magnetic resonance logging T2 sub-spectra by using the pore fluid type calibration feature to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, the method further includes:

[0016] Obtaining compensated neutron logging data and clay mineral content of the shale in the target interval;

[0017] Based on the nuclear magnetic resonance logging data and the compensated neutron logging data, determining a clay mineral structure water content of the target interval;

[0018] In the case of core depth homing, based on the clay mineral structure water content and the clay mineral content, a mapping regression relationship is constructed to obtain a continuous longitudinal shale clay mineral content of the shale;

[0019] The continuous longitudinal shale clay mineral content is used to calibrate the pore fluid type and corresponding T1-T2 signal interval distribution, to obtain the pore fluid type calibration feature.

[0020] In a possible implementation, the calibration of the pore fluid type and corresponding T1-T2 signal interval distribution based on the continuous longitudinal shale clay mineral content includes:

[0021] The low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum of the core sample of the shale in the target layer is determined, and the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum is used to indicate the T1-T2 spectrum of the core sample under different core saturation states.

[0022] The difference between the continuous longitudinal shale clay mineral content and the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum is determined.

[0023] The pore fluid type and corresponding T1-T2 signal interval distribution are calibrated based on the difference, to obtain the pore fluid type calibration feature.

[0024] In a possible implementation, the nuclear magnetic resonance logging data includes a nuclear magnetic resonance T2 spectrum, and before the data analysis of the nuclear magnetic resonance logging data is performed to obtain the corresponding multiple nuclear magnetic resonance logging T2 sub-spectra, the method further includes:

[0025] Based on the clay mineral content and the clay mineral content threshold, a clay mineral content difference parameter is determined.

[0026] The nuclear magnetic resonance T2 spectrum is standardized based on the clay mineral content difference parameter.

[0027] The standardized nuclear magnetic resonance T2 spectrum is subjected to a smoothing filtering process.

[0028] In a possible implementation, the multiple nuclear magnetic resonance logging T2 sub-spectra include:

[0029] A clay bound fluid spectrum, a capillary bound fluid spectrum, a mesopore movable fluid spectrum, and a macropore movable fluid spectrum.

[0030] In a second aspect, the present application provides a device for determining shale pore fluid type and porosity, comprising:

[0031] An acquisition module is configured to acquire nuclear magnetic resonance logging data of shale in a target layer, and perform T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain corresponding multiple nuclear magnetic resonance logging T2 sub-spectra.

[0032] The processing module is configured to perform fluid type calibration on the multiple NMR logging T2 sub-spectra by using a pore fluid type calibration feature, to obtain a fluid type corresponding to each NMR logging T2 sub-spectrum, wherein the pore fluid type calibration feature is used to indicate a T1-T2 signal interval distribution corresponding to multiple pore fluid types, and the pore fluid type calibration feature is determined according to differences in T1-T2 spectra under different clay mineral content shale and different core saturation states.

[0033] The processing module is further configured to determine effective porosity and movable fluid porosity of the shale based on the multiple NMR logging T2 sub-spectra and the corresponding fluid types.

[0034] In a possible implementation, the processing module is configured to perform component analysis on the NMR logging data by using an independent component analysis technology, to obtain a corresponding T2 spectrum signal matrix; perform multi-component signal and peak spectrum sorting processing on the T2 spectrum signal matrix based on a sparse non-negative matrix factorization technology, to obtain multiple candidate NMR logging T2 sub-spectra; and strip abnormal noise spectra in the multiple candidate NMR logging T2 sub-spectra, to obtain the multiple NMR logging T2 sub-spectra.

[0035] In a possible implementation, the acquisition module is further configured to acquire compensated neutron logging data and clay mineral content of the shale in the target interval.

[0036] The processing module is further configured to determine clay mineral structure water content of the target interval based on the target NMR sub-data and the compensated neutron logging data; in the case of core depth homing, construct a mapping regression relationship based on the clay mineral structure water content and the clay mineral content, to obtain continuous longitudinal shale clay mineral content of the shale; and

[0037] Perform calibration processing on pore fluid types and corresponding T1-T2 signal interval distributions based on the continuous longitudinal shale clay mineral content, to obtain the pore fluid type calibration feature.

[0038] In a possible implementation, the processing module is configured to determine a low-frequency multi-state two-dimensional NMR experiment T1-T2 spectrum of a core sample of the shale in the target interval, the low-frequency multi-state two-dimensional NMR experiment T1-T2 spectrum is used to indicate T1-T2 spectra of the core sample under different core saturation states; determine differences between the continuous longitudinal shale clay mineral content and the low-frequency multi-state two-dimensional NMR experiment T1-T2 spectrum; and perform calibration processing on pore fluid types and corresponding T1-T2 signal interval distributions based on the differences, to obtain the pore fluid type calibration feature.

[0039] In a possible implementation, the processing module is further configured to determine a clay mineral content difference parameter based on the clay mineral content and a clay mineral content threshold value; perform standardization processing on the NMR T2 spectrum based on the clay mineral content difference parameter; and perform smoothing filtering processing on the NMR T2 spectrum after the standardization processing.

[0040] In a possible implementation, the plurality of NMR logging T2 sub-spectra comprises:

[0041] A clay bound fluid spectrum, a capillary bound fluid spectrum, a mesopore movable fluid spectrum, and a macropore movable fluid spectrum.

[0042] In a third aspect, the present application provides a shale pore fluid type and porosity determination device, comprising:

[0043] comprising a processor and a memory connected to the processor in communication;

[0044] The memory stores computer execution instructions.

[0045] The processor executes the computer execution instructions stored in the memory to implement the method of the first aspect and various possible implementation manners of the first aspect.

[0046] In a fourth aspect, the present application provides a computer readable storage medium, the computer readable storage medium stores computer execution instructions, and the computer execution instructions are executed by a processor to implement the method of the first aspect and various possible implementation manners of the first aspect.

[0047] In a fifth aspect, the present application provides a computer program product, comprising a computer program, and the computer program is executed by a processor to implement the method of the first aspect and various possible implementation manners of the first aspect.

[0048] The application provides a shale pore fluid type and porosity determination method, device and medium, which comprises the following steps: obtaining nuclear magnetic resonance logging data of shale in a target layer, and performing T2 spectrum component stripping processing to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra; determining pore fluid type calibration characteristics according to differences in T1-T2 spectrum diagrams of shale with different clay mineral contents and under different core saturation states; performing fluid type calibration on the plurality of nuclear magnetic resonance logging T2 sub-spectra based on the pore fluid type calibration characteristics to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum; and determining effective porosity and movable fluid porosity of the shale based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid type. The method improves the calculation accuracy of porosity, and provides a simple and reliable method for fluid type discrimination and porosity calculation of logging which only measures one-dimensional nuclear magnetic resonance logging and has no coring nuclear magnetic resonance experiment. BRIEF DESCRIPTION OF DRAWINGS

[0049] The accompanying drawings, which are incorporated herein and form a part of the specification, illustrate embodiments consistent with the present application and, together with the description, further serve to explain the principles of the application.

[0050] Figure 1 A shale pore fluid type and porosity determination method provided by the embodiment of the application Figure One

[0051] Figure 2 A plurality of nuclear magnetic resonance logging T2 sub-spectra shown by the embodiment of the application

[0052] Figure 3 A plurality of nuclear magnetic resonance logging T2 sub-spectra and pore fluid type calibration characteristics provided by the embodiment of the application

[0053] Figure 4 A calculation result diagram of effective porosity and movable fluid porosity provided by the embodiment of the application

[0054] Figure 5 A shale pore fluid type and porosity determination method provided by the embodiment of the application Figure Two

[0055] Figure 6 A continuous longitudinal shale clay mineral content diagram provided by the embodiment of the application

[0056] Figure 7 A structure diagram of a shale pore fluid type and porosity determination device provided by the embodiment of the application

[0057] Figure 8 ​​A structural schematic diagram of a shale pore fluid type and porosity determination device provided in an embodiment of the present application.

[0058] The specific embodiments of the present application have been shown through the above drawings, and will be described in more detail hereinafter. These drawings and the written description are not intended to restrict the scope of the present application in any way, but to illustrate the present application to those skilled in the art by referring to specific embodiments. DETAILED DESCRIPTION

[0059] In order to make the objectives, technical solutions and advantages of the present application clearer, the technical solutions of the present application will be described clearly and completely below in conjunction with the drawings in the present application. Obviously, the described embodiments are only some of the embodiments of the present application, rather than all the embodiments. Based on the embodiments in the present application, all other embodiments obtained by those skilled in the art without creative work fall within the scope of protection of the present application.

[0060] The terms "first", "second", "third", "fourth" and the like (if any) in the description, claims, and drawings of the present application are used to distinguish similar objects, and do not necessarily have to be used to describe a particular order or sequence. It should be understood that the data thus used can be interchanged under appropriate circumstances, so that the embodiments of the present application described herein can be implemented in an order other than that illustrated or described herein.

[0061] In the embodiments of the present application, the words "exemplary" or "for example" are used to mean example, illustration, or illustration. Any embodiment or design solution described as "exemplary" or "for example" in the present application should not be interpreted as more preferred or more advantageous than other embodiments or design solutions. Rather, the use of "exemplary" or "for example" is intended to present the relevant concept in a specific manner.

[0062] As a typical unconventional reservoir, shale has the characteristics of fine-grained mixing of multiple sources and multiple types of minerals, complex micro-nanopore structure, etc. The quality evaluation and efficient development of shale oil reservoirs largely depend on the accurate characterization of fluid mobility in shale pores. The oil and gas accumulation process of shale oil reservoirs is a self-generation and self-storage mode of organic matter generation and accumulation, which is significantly different from the buoyancy-driven conventional reservoirs. This particularity leads to more complex fluid types and spatial distribution in shale pores, and it is difficult to finely characterize them. The pore space that can store oil and gas in shale reservoirs is all effective pores, i.e. the effective porosity only excludes the part occupied by clay bound water. Therefore, accurate calculation of the effective porosity of shale is crucial for reservoir evaluation.

[0063] At present, the commonly used method for determining the effective porosity of shale in the prior art usually includes core experiment analysis method and logging T2 cutoff value method.

[0064] Core experiment analysis method mainly needs to measure the core by using a two-dimensional nuclear magnetic resonance core analyzer in a laboratory, establish a T1-T2 fluid type identification chart, so as to realize fluid type discrimination and corresponding porosity calculation. However, due to the high cost of downhole shale coring and laboratory measurement, it is difficult to realize longitudinal continuous characterization; and the magnetic field strength, frequency and other parameters of different instruments have not been unified, so that the detection results are difficult to be directly calibrated and applied to nuclear magnetic resonance logging data analysis.

[0065] Logging T2 cutoff value method is based on the difference of T2 transverse relaxation time distribution of different pore fluids, and sets the cutoff value T 2cutoff , so as to realize corresponding porosity calculation by using integral method. This method mainly relies on core experiment calibration logging to determine T2 cutoff value, and the calculation is simple. However, both fixed T2 cutoff value and variable T2 cutoff value method lack consideration of factors such as complex pore structure and fluid type distribution of shale. Especially for shale with high clay content and low porosity, the signals of clay bound fluid and capillary bound fluid are difficult to separate, and abnormal noise signals exist interference, which will cause large error in porosity calculation, thereby affecting the evaluation of shale reservoir quality.

[0066] In view of the problems in the prior art, the present application provides a method for determining shale pore fluid type and porosity. The method obtains nuclear magnetic resonance logging data of shale in a target interval, and performs T2 spectrum component separation processing to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra. The porosity fluid type calibration feature is determined according to the difference of T1-T2 spectrum chart under different clay mineral content shale and different core saturation state. The fluid type calibration is performed on the plurality of nuclear magnetic resonance logging T2 sub-spectra based on the porosity fluid type calibration feature, to obtain the fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum. Then, the effective porosity and movable fluid porosity of shale are determined based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid type. The method improves the calculation accuracy of porosity, and provides a simple and reliable method for fluid type discrimination and porosity calculation of logging which only measures one-dimensional nuclear magnetic resonance logging and has no coring nuclear magnetic resonance experiment.

[0067] The technical solutions of the present application and how the technical solutions of the present application solve the above technical problems will be described in detail below with specific examples. The following specific examples can be implemented independently, or can be combined with each other. For the same or similar concepts or processes, some examples may not be described again.

[0068] Figure 1 A flowchart of a shale pore fluid type and porosity determination method provided by an embodiment of the present application Figure One . For example Figure 1As shown, the shale pore fluid type and porosity determination method provided by the embodiment includes:

[0069] S101, obtain the nuclear magnetic resonance logging data of shale in a target layer section, and perform T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain a plurality of corresponding nuclear magnetic resonance logging T2 sub-spectra.

[0070] The target layer section may be any layer section of shale, for example.

[0071] It can be understood that, due to the complex pore structure and complex fluid type distribution of shale, the nuclear magnetic resonance logging T2 spectrum contains more signal components, and may also contain abnormal noise signals; therefore, the nuclear magnetic resonance logging T2 spectrum needs to be subjected to T2 spectrum component stripping processing to distinguish the signal components therein, so as to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra.

[0072] In a possible implementation, the specific implementation of obtaining the plurality of nuclear magnetic resonance logging T2 sub-spectra may include, for example:

[0073] First, an independent component analysis (ICA) technology is used to perform component analysis on the nuclear magnetic resonance logging data to obtain a corresponding T2 spectrum signal matrix;

[0074] ICA is a blind source separation technology for separating statistically independent non-Gaussian components from multivariate signals, which assumes that the mixed signals are linear combinations of multiple independent source signals, and the source signals have non-Gaussian distribution characteristics. The goal is to estimate the original source signals by demixing the matrix, and finally make the separated components statistically independent.

[0075] In this step, ICA assumes that the nuclear magnetic resonance logging T2 spectrum observation signal is a linear combination of several independent source signals, so the T2 spectrum signal matrix can be represented as:

[0076]

[0077] wherein X is the nuclear magnetic resonance logging T2 spectrum observation signal matrix; S k corresponding to a plurality of fluid type T2 sub-spectrum signal matrices; N represents the number of sub-spectra.

[0078] For example, N may be 4, S 1-4 may be used to represent the clay bound fluid spectrum, the capillary bound fluid spectrum, the mesopore movable fluid spectrum, and the macropore movable fluid spectrum, respectively; and S5 is used to represent the abnormal noise spectrum.

[0079] Since the essence of the signal in the T2 spectrum of the nuclear magnetic resonance logging is a linear superposition of multi-exponential decay signals of different pore fluids, ICA can better capture statistically independent components than principal components analysis (PCA) to meet the spatial independence of fluid occurrence.

[0080] After obtaining the T2 spectrum signal matrix, blind source separation is performed on the T2 spectrum signal matrix:

[0081]

[0082] Wherein, A is a mixing matrix, and S is a nuclear magnetic resonance logging T2 spectrum observation signal matrix.

[0083] Then, multi-component signal stripping and peak spectrum sorting processing are performed on the T2 spectrum signal matrix based on a sparse non-negative matrix factorization technology, to obtain a plurality of candidate nuclear magnetic resonance logging T2 sub-spectra.

[0084] The non-negative sparse matrix is decomposed by using a sparse non-negative matrix factorization (SNMF) technology;

[0085] SNMF is an improved method of introducing sparsity constraint on the basis of traditional non-negative matrix factorization (NMF), and the core target is to realize more efficient data dimension reduction and feature extraction by constraining the sparsity of the decomposed matrix.

[0086] In this step, the non-negative sparse matrix decomposition can be performed by using the following formula:

[0087]

[0088] Wherein, W is a plurality of fluid type T2 sub-spectrum signal matrices; H is a coefficient matrix, representing the relative contribution weight of different fluid components at each depth point.

[0089] The sparsity optimization target is:

[0090]

[0091] Wherein, α and β are sparsity constraint parameters.

[0092] It can be understood that this step introduces an adaptive regularization parameter to constrain sparsity and strengthen T2 sub-spectrum peak positioning.

[0093] Figure 2 FIG. 1 is a schematic diagram of a plurality of nuclear magnetic resonance logging T2 sub-spectra shown in the embodiments of the present application. As shown in FIG. 1, the T2 sub-spectrum of each fluid type is represented by a peak, and the height of the peak represents the relative contribution weight of the fluid type at each depth point. Figure 2As shown, due to the complexity of the signal components in the original T2 spectrum, there is no obvious feature.

[0094] The plurality of candidate NMR logging T2 sub-spectra include: clay bound fluid spectrum, capillary bound fluid spectrum, mesopore movable fluid spectrum, macropore movable fluid spectrum, and abnormal noise spectrum. After multi-component signal stripping and spectral peak sorting of the original T2 spectrum by using the ICA+SNMF mode, the plurality of sub-spectra are obtained.

[0095] Since the abnormal noise needs to be removed in the subsequent calculation process, the abnormal noise spectrum is stripped from the plurality of candidate NMR logging T2 sub-spectra, and the plurality of NMR logging T2 sub-spectra are obtained.

[0096] In a possible implementation, before determining the plurality of NMR logging T2 sub-spectra, the NMR T2 spectrum can also be subjected to standardization processing and filtering processing, specifically as follows:

[0097] Since the clay mineral content has an impact on the NMR T2 spectrum, the clay mineral content difference parameter can be determined based on the clay mineral content and the clay mineral content threshold, and the NMR T2 spectrum is subjected to standardization processing based on the clay mineral content difference parameter.

[0098] The clay mineral content is the mineral content corresponding to the core sample of the target interval. The standardization processing process can use the following formula, for example:

[0099]

[0100] wherein, is the amplitude value of the data point of the i-th NMR T2 spectrum after standardization; is the original amplitude value of the data point of the i-th NMR T2 spectrum; is the mean value of the NMR T2 spectrum; is the standard deviation of the NMR T2 spectrum; is the clay mineral content; is the clay mineral content threshold; k is a dynamic adjustment factor, which is related to the shale formation.

[0101] The above standardization processing comprehensively considers the impact of the clay mineral content on the NMR T2 spectrum, and introduces the clay mineral content difference term , and realizes the dynamic adjustment of the nonlinear sensitivity corresponding to the clay mineral content threshold through the S-shaped growth curve.

[0102] The NMR T2 spectrum after standardization processing is subjected to smoothing filtering processing,

[0103] In this step, a S-G (Savitzky-Golay) filter can be used for filtering processing. For example, the following formula can be used:

[0104]

[0105] wherein, is an amplitude value of a data point of the i th filtered nuclear magnetic resonance T2 spectrum; is an amplitude value of a data point of the i+j th nuclear magnetic resonance T2 spectrum in the sliding window; is a filtering convolution coefficient; k is a window radius, and the total window length is 2k+1.

[0106] The local data in the sliding window is least square fitted by using a low-order polynomial to calculate a smooth estimation value of the center point. The S-G filtering realizes the smooth noise reduction, and reduces the peak position deviation to the greatest extent, and maintains the spectral peak shape and other characteristics.

[0107] S102, a pore fluid type calibration feature is used to calibrate the fluid type of the plurality of nuclear magnetic resonance logging T2 sub-spectra, to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum.

[0108] The pore fluid type calibration feature can be used to indicate, for example, the T1-T2 signal interval distribution corresponding to a plurality of pore fluid types, and the pore fluid type calibration feature is determined according to the difference between T1-T2 spectra under different clay mineral content shale and different core saturation. The fluid type can include, for example, clay bound fluid type, capillary bound fluid type, mesopore movable fluid type, and macropore movable fluid type.

[0109] In this step, since the plurality of nuclear magnetic resonance logging T2 sub-spectra has been obtained, the fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum can be determined based on the pore fluid type calibration feature.

[0110] Figure 3 A schematic diagram of a plurality of nuclear magnetic resonance logging T2 sub-spectra and a pore fluid type calibration feature provided by an embodiment of the present application is shown in FIG. 1. Figure 3 As shown in FIG. 1, there is a corresponding relationship between the nuclear magnetic resonance logging T2 sub-spectrum and the pore fluid type calibration feature,

[0111] For example, at 4629.62 m, the results of the plurality of nuclear magnetic resonance logging T2 sub-spectra are high-amplitude clay bound fluid spectrum, low-amplitude capillary bound fluid spectrum, extremely low-amplitude mesopore movable fluid spectrum, no macropore movable fluid spectrum, and abnormal noise spectrum; the results of the pore fluid type calibration feature are strong clay bound water and capillary bound water signals, weak bound oil and movable oil signals; the results of the two are basically consistent.

[0112] At 4665.69 m, the results of the multiple NMR logging T2 sub-spectrum are high-amplitude clay bound fluid spectrum, medium-amplitude capillary bound fluid spectrum, high-amplitude medium-pore movable fluid spectrum, low-amplitude large-pore movable fluid spectrum, and no abnormal noise spectrum; the results of the pore fluid type calibration feature are strong clay bound water signal, medium bound oil signal, and strong movable oil signal, which are basically consistent.

[0113] The above results not only verify the accuracy of the decomposition and noise stripping of the multiple NMR logging T2 sub-spectrum, but also reflect the simplicity of the pore fluid type calibration feature compared with the two-dimensional NMR T1-T2 spectrum for identifying fluid types.

[0114] S103, based on the multiple NMR logging T2 sub-spectrum and the corresponding fluid type, determining the effective porosity and movable fluid porosity of the shale.

[0115] After obtaining the fluid type corresponding to each NMR logging T2 sub-spectrum, the porosities of four different pore fluid components, i.e., clay bound fluid, capillary bound fluid, medium-pore movable fluid, and large-pore movable fluid, can be calculated respectively by using the integral method.

[0116] In one possible implementation, the following formula can be used, for example:

[0117]

[0118] wherein, represent the porosities of different pore fluid components, respectively; represent the NMR logging T2 sub-spectrum of different pore fluid components, respectively; T 2min and T 2max are the minimum and maximum values of the transverse relaxation time of the NMR logging T2 sub-spectrum;

[0119]

[0120]

[0121] wherein, represents the effective porosity; represents the movable fluid porosity.

[0122] Figure 4 FIG. 1 is a schematic diagram of a calculation result of effective porosity and movable fluid porosity provided by an embodiment of the present application. As shown in FIG. 1, there are multiple round dots in the two columns corresponding to the effective porosity, and the round dots are the actually measured effective porosities. Figure 4

[0123] ​It can be understood that there is a difference between the effective porosity calculated by the traditional 3ms cutoff method and the effective porosity calculated by the embodiment of the present application, and the effective porosity calculated by the embodiment of the present application is more consistent with the measured effective porosity of the core, which also shows that the method provided by the embodiment of the present application improves the calculation accuracy of the effective porosity.

[0124] The method for determining shale pore fluid type and porosity provided by the embodiment comprises the following steps: obtaining nuclear magnetic resonance logging data of shale in a target layer section, and performing T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain a plurality of corresponding nuclear magnetic resonance logging T2 sub-spectra; determining pore fluid type calibration features according to differences in T1-T2 spectrum graphs of shale with different clay mineral contents and under different core saturation states; performing fluid type calibration on the plurality of nuclear magnetic resonance logging T2 sub-spectra based on the pore fluid type calibration features to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum; and determining effective porosity and movable fluid porosity of the shale based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid types. The method improves the calculation accuracy of porosity, and provides a simple and reliable method for fluid type discrimination and porosity calculation of logging that only measures one-dimensional nuclear magnetic resonance logging and has no coring nuclear magnetic resonance experiment.

[0125] Figure 5 The method for determining shale pore fluid type and porosity provided by the embodiment of the present application Figure Two The embodiment is based on Figure 1 The embodiment is based on Figure 5 As shown in the figure, the method comprises the following steps:

[0126] S201, obtaining compensated neutron logging data of shale in a target layer section and clay mineral content.

[0127] The neutron logging is a kind of neutron logging method for overcoming the influence of irregular changes of wellbore after layout correction based on neutron logging, which records two neutron curves with different source distances to calculate porosity in open hole or cased hole.

[0128] The main principle includes: isotopic neutron source (18Ci americium-beryllium neutron source) emits fast neutrons to the formation in the wellbore, and then two long and short thermal neutron detectors with different source distances are used to measure the thermal neutrons slowed down and scattered back to the wellbore, and two count rates are obtained. The ratio of the count rates of the short source distance and the long source distance detectors mainly reflects the deceleration ability of the formation to the fast neutrons, so as to characterize the change of hydrogen content in the formation.

[0129] The clay mineral content may be obtained by X-ray diffraction method, for example.

[0130] S202, determining the clay mineral structure water content of the target layer based on the nuclear magnetic resonance logging data and the compensated neutron logging data.

[0131] wherein, Figure 6 is a schematic diagram of continuous longitudinal shale clay mineral content provided by the embodiment of the present application.

[0132] As Figure 6 indicated, the nuclear magnetic effective porosity mainly includes: the porosity of the capillary bound fluid type and the porosity of the movable fluid type;

[0133] The nuclear magnetic total porosity mainly includes: the clay bound water porosity, the porosity of the capillary bound fluid type and the porosity of the movable fluid type;

[0134] The compensated neutron porosity mainly includes: the clay structure water porosity, the clay bound water porosity, the porosity of the capillary bound fluid type and the porosity of the movable fluid type.

[0135] Based on this, the difference between the nuclear magnetic resonance logging data and the compensated neutron logging data is the clay structure water porosity.

[0136] Therefore, the difference between the nuclear magnetic resonance logging data and the compensated neutron logging data can be determined as the porosity corresponding to the clay mineral structure water in the shale, that is, the clay mineral structure water content. Specifically, the following formula can be used:

[0137]

[0138] wherein, is the clay mineral structure water porosity; is the compensated neutron porosity corresponding to the compensated neutron logging data; is the nuclear magnetic total porosity corresponding to the nuclear magnetic resonance logging data.

[0139] S203, constructing a mapping regression relationship based on the clay mineral structure water content and the clay mineral content to obtain the continuous longitudinal shale clay mineral content of the shale under the condition of core depth homing.

[0140] Wherein, the purpose of core depth homing is to restore the real depth of the core to obtain more accurate data.

[0141] In this step, for example, the following formula can be used to determine the continuous longitudinal shale clay mineral content:

[0142]

[0143] wherein, is the clay mineral content volume; is the porosity of the structural water of the clay mineral; a and b are the correlation coefficients of rock diagenesis.

[0144] With reference to the foregoing Figure 6 It can be seen that the continuous longitudinal shale clay mineral content corresponds to the two porosities described above, and therefore a mapping regression relationship can be established based on the corresponding data of the core sample of the target interval to obtain the continuous longitudinal shale clay mineral content.

[0145] In S204, the continuous longitudinal shale clay mineral content is used to calibrate the pore fluid type and the corresponding T1-T2 signal interval distribution to obtain the pore fluid type calibration feature.

[0146] After the continuous longitudinal shale clay mineral content is obtained, the T1-T2 spectrum of the core under multiple saturation states can be used to calibrate the pore fluid type and the corresponding T1-T2 signal interval distribution to obtain the pore fluid type calibration feature.

[0147] In one possible implementation, the specific implementation of step S204 includes:

[0148] The low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum of the core sample of the shale in the target interval is determined.

[0149] The low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum is used to indicate the T1-T2 spectrum of the core sample under different core saturation states. It can be understood that the T1-T2 spectrum data of the core sample is different when it is in different core saturation states.

[0150] The difference between the continuous longitudinal shale clay mineral content and the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum is determined.

[0151] The difference is used to calibrate the pore fluid type and the corresponding T1-T2 signal interval distribution to obtain the pore fluid type calibration feature.

[0152] The method for determining the shale pore fluid type and porosity provided by the embodiments of the present application compensates for the structural water porosity of the clay mineral through neutron logging and nuclear magnetic resonance logging; on the basis of the core depth homing, a mapping regression relationship is established between the structural water porosity of the clay mineral and the clay mineral content to output a continuous longitudinal shale clay mineral content curve, and then the continuous longitudinal shale clay mineral content is used to calibrate the pore fluid type and the corresponding T1-T2 signal interval distribution; this method can avoid the defects of high cost and data dispersion caused by relying solely on coring experiments to determine the clay mineral content, and can efficiently determine the fluid type and reduce the expensive cost of using system coring experiments to calibrate logging.

[0153] Figure 7 A structural schematic diagram of a shale pore fluid type and porosity determination device provided for an embodiment of the present application. As shown in the figure, the shale pore fluid type and porosity determination device 700 comprises: Figure 7

[0154] An acquisition module 701 is configured to acquire nuclear magnetic resonance logging data of shale in a target interval, and perform T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain a plurality of nuclear magnetic resonance logging T2 sub-spectra corresponding thereto.

[0155] A processing module 702 is configured to perform fluid type calibration on the plurality of nuclear magnetic resonance logging T2 sub-spectra by using pore fluid type calibration features, to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, wherein the pore fluid type calibration features are used to indicate T1-T2 signal interval distributions corresponding to a plurality of pore fluid types, and the pore fluid type calibration features are determined according to differences in T1-T2 spectrum diagrams under different clay mineral content shale and different core saturation states.

[0156] The processing module 702 is further configured to determine effective porosity and movable fluid porosity of the shale based on the plurality of nuclear magnetic resonance logging T2 sub-spectra and the corresponding fluid types.

[0157] In a possible implementation manner, the processing module 702 is configured to perform component analysis on the nuclear magnetic resonance logging data by using an independent component analysis technology to obtain a T2 spectrum signal matrix corresponding thereto; perform multi-component signal and peak spectrum sorting processing on the T2 spectrum signal matrix based on a sparse non-negative matrix factorization technology to obtain a plurality of candidate nuclear magnetic resonance logging T2 sub-spectra; and strip abnormal noise spectrum in the plurality of candidate nuclear magnetic resonance logging T2 sub-spectra to obtain the plurality of nuclear magnetic resonance logging T2 sub-spectra.

[0158] In a possible implementation manner, the acquisition module 701 is further configured to acquire compensated neutron logging data and clay mineral content of the shale in the target interval.

[0159] The processing module 702 is further configured to determine clay mineral structure water content of the target interval based on the target nuclear magnetic resonance sub-data and the compensated neutron logging data; in the case of core depth homing, construct a mapping regression relationship based on the clay mineral structure water content and the clay mineral content to obtain continuous longitudinal shale clay mineral content of the shale; and

[0160] Perform calibration processing on pore fluid types and corresponding T1-T2 signal interval distributions based on the continuous longitudinal shale clay mineral content to obtain the pore fluid type calibration features. ​

[0161] In a possible implementation, the processing module 702 is configured to determine a low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum of the shale in a core sample of the target interval, the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum is used to indicate a T1-T2 spectrum of the core sample under different core saturation states; determine a difference condition between the continuous longitudinal shale clay mineral content and the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum; and based on the difference condition, calibrate a pore fluid type and a corresponding T1-T2 signal interval distribution to obtain the pore fluid type calibration feature.

[0162] In a possible implementation, the processing module 702 is further configured to determine a clay mineral content difference parameter based on the clay mineral content and a clay mineral content threshold; perform standardization processing on the nuclear magnetic resonance T2 spectrum based on the clay mineral content difference parameter; and perform smoothing filtering processing on the nuclear magnetic resonance T2 spectrum after the standardization processing.

[0163] In a possible implementation, the plurality of nuclear magnetic resonance logging T2 sub-spectra includes:

[0164] A clay bound fluid spectrum, a capillary bound fluid spectrum, a mesopore movable fluid spectrum, and a macropore movable fluid spectrum.

[0165] The shale pore fluid type and porosity determination apparatus provided in this embodiment can perform the method provided in the method embodiments, and has similar implementation principles and technical effects. Therefore, no further description is given herein.

[0166] Figure 8 FIG. 8 shows a structural schematic diagram of a shale pore fluid type and porosity determination device provided in this embodiment. As shown in the figure, the shale pore fluid type and porosity determination device 800 can include at least one processor 801, at least one memory 802, and a communication interface 803. The at least one processor 801 is configured to implement the method provided in the above embodiments. Figure 8

[0167] The at least one memory 802 is configured to store program instructions and / or data. The memory 802 and the processor 801 are coupled. The coupling in this embodiment is indirect coupling or communication connection between devices, units, or modules, which can be electrical, mechanical, or other forms, and is used for information interaction between devices, units, or modules. The processor 801 can operate in cooperation with the memory 802. The processor 801 can execute the program instructions stored in the memory 802. At least one of the at least one memory can be included in the processor.

[0168] ​The communication interface 803 is configured to communicate with other devices through a transmission medium, so that the shale pore fluid type and porosity determination device 800 can communicate with other devices. The communication interface 803 can be, for example, a transceiver, an interface, a bus, a circuit or a device capable of realizing the transceiving function. The processor 801 can utilize the communication interface 803 to transceive data and / or information, and is configured to implement the method provided by the above-mentioned embodiments. For details, refer to the detailed description in the above embodiments, which will not be repeated here.

[0169] The specific connection medium between the processor 801, the memory 802 and the communication interface 803 is not limited in the embodiments of the present application. In the embodiments of the present application, the processor 801, the memory 802 and the communication interface 803 are connected through a bus 804. Figure 8 Figure 8 The connection mode between other components is only schematically illustrated, and is not limited. The bus can be divided into an address bus, a data bus, a control bus and the like. For convenience of representation, only one thick line is used to represent the bus in the figure, but it does not mean that there is only one bus or only one type of bus. Figure 8

[0170] The embodiments of the present application also provide a computer readable storage medium, which stores a computer program. The computer program is executed by a processor to implement the technical solutions of the above-mentioned method embodiments, and the implementation principles and technical effects are similar, which will not be repeated here.

[0171] The embodiments of the present application also provide a computer program product, which includes a computer program. The computer program is executed by a processor to implement the technical solutions of the above-mentioned method embodiments, and the implementation principles and technical effects are similar, which will not be repeated here.

[0172] It should be noted that, for the above-mentioned method embodiments, in order to simply describe, they are all expressed as a series of action combinations, but those skilled in the art should know that the present application is not limited to the action order described, because according to the present application, certain steps can be performed in other order or simultaneously. Secondly, those skilled in the art should know that the embodiments described in the specification are all optional embodiments, and the actions and modules involved are not necessarily required by the present application.

[0173] ​​It should be further noted that although the steps in the flowchart are shown sequentially according to the arrows, these steps are not necessarily executed in the order indicated by the arrows. Unless explicitly stated herein, there is no strict order restriction on the execution of these steps, and they can be executed in other orders. Moreover, at least some steps in the flowchart may include multiple sub-steps or multiple stages. These sub-steps or stages are not necessarily completed at the same time, but can be executed at different times. The execution order of these sub-steps or stages is not necessarily sequential, but can be performed alternately or in turn with other steps or at least some of the sub-steps or stages of other steps.

[0174] It should be understood that the above-described device embodiments are merely illustrative, and the device of this application can also be implemented in other ways. For example, the division of units / modules in the above embodiments is only a logical functional division, and there may be other division methods in actual implementation. For example, multiple units, modules, or components may be combined, or integrated into another system, or some features may be ignored or not executed.

[0175] Furthermore, unless otherwise specified, the functional units / modules in the various embodiments of this application can be integrated into one unit / module, or each unit / module can exist physically separately, or two or more units / modules can be integrated together. The integrated units / modules described above can be implemented in hardware or as software program modules.

[0176] When integrated units / modules are implemented in hardware, the hardware can be digital circuits, analog circuits, etc. The physical implementation of the hardware structure includes, but is not limited to, transistors, memristors, etc. Unless otherwise specified, the processor can be any suitable hardware processor, such as a CPU, GPU, FPGA, DSP, and ASIC, etc. Unless otherwise specified, the storage unit can be any suitable magnetic or magneto-optical storage medium, such as Resistive Random Access Memory (RRAM), Dynamic Random Access Memory (DRAM), Static Random Access Memory (SRAM), Enhanced Dynamic Random Access Memory (EDRAM), High-Bandwidth Memory (HBM), Hybrid Memory Cube (HMC), etc.

[0177] If the integrated units / modules are implemented in the form of software program modules and sold or used as independent products, they can be stored in a computer readable memory. Based on such understanding, the technical solutions of the present application essentially or the part that contributes to the prior art or the whole or part of the technical solutions can be embodied in the form of a software product. The computer software product is stored in a memory and includes a number of instructions for causing a computer device (which can be a personal computer, a server or a network device, etc.) to execute all or part of the steps of the embodiments of the method of the present application. The aforementioned memory includes: a U disk, a read-only memory (ROM, Read-Only Memory), a random access memory (RAM, Random Access Memory), a mobile hard disk, a magnetic disk or an optical disk, and various media that can store program codes.

[0178] In the above embodiments, the description of each embodiment has its own focus, and the parts not described in detail in a certain embodiment can be referred to the related description of other embodiments. The technical features of the above embodiments can be combined arbitrarily. In order to make the description concise, not all possible combinations of the technical features in the above embodiments are described, however, as long as the combinations of the technical features do not exist contradictory, they should be considered as the scope of the present application.

[0179] Other embodiments of the application will be apparent to those skilled in the art from consideration of the specification and practice of the application disclosed herein. The application is intended to cover any variations, uses or adaptations of the application following, in general, the principles of the application and including such departures from the present disclosure as come within known or customary practice in the art to which the application pertains or can relate. The specification and examples are to be regarded as exemplary only, and the true scope and spirit of the application are indicated by the following claims.

[0180] It should be understood that the application is not limited to the precise construction that has been described above and illustrated in the accompanying drawings, and that various modifications and changes can be made without departing from the scope thereof. The scope of the application is limited only by the claims that follow.

Claims

1. A method of determining shale pore fluid type and porosity, characterized by, The method is applied to a shale oil and gas exploration scene, and the method comprises the following steps: Obtaining nuclear magnetic resonance logging data of shale in a target interval, and performing T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain corresponding multiple nuclear magnetic resonance logging T2 sub-spectra; Obtaining compensated neutron logging data and clay mineral content of the shale in the target interval; Based on the nuclear magnetic resonance logging data and the compensated neutron logging data, determining the clay mineral structure water content of the target interval; In the case of core depth homing, based on the clay mineral structure water content and the clay mineral content, a mapping regression relationship is constructed to obtain continuous longitudinal shale clay mineral content of the shale; Determine the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum of the core sample of the shale in the target interval, which is used to indicate the T1-T2 spectrum of the core sample under different core saturation states; Determine the difference between the continuous longitudinal shale clay mineral content and the low-frequency multi-state two-dimensional nuclear magnetic resonance experiment T1-T2 spectrum; Based on the difference, the pore fluid type and the corresponding T1-T2 signal interval distribution are calibrated to obtain the pore fluid type calibration feature; Using the pore fluid type calibration feature to calibrate the fluid type of multiple nuclear magnetic resonance logging T2 sub-spectra to obtain the corresponding fluid type of each nuclear magnetic resonance logging T2 sub-spectrum, wherein the pore fluid type calibration feature is used to indicate the T1-T2 signal interval distribution corresponding to multiple pore fluid types, and the pore fluid type calibration feature is determined according to the difference of T1-T2 spectrum under different clay mineral content shale and different core saturation states; Based on multiple nuclear magnetic resonance logging T2 sub-spectra and corresponding fluid types, determine the effective porosity and movable fluid porosity of the shale, the effective porosity is the sum of the porosities corresponding to capillary bound fluid, mesopore movable fluid and macropore movable fluid, and the movable fluid porosity is the sum of the porosities corresponding to mesopore movable fluid and macropore movable fluid.

2. The method of claim 1, wherein, The T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain corresponding multiple nuclear magnetic resonance logging T2 sub-spectra comprises: Using independent component analysis technology to perform component analysis on nuclear magnetic resonance logging data to obtain corresponding T2 spectrum signal matrix; Based on the sparse non-negative matrix factorization technology, the T2 spectrum signal matrix is processed by multi-component signal and peak spectrum sorting to obtain multiple candidate nuclear magnetic resonance logging T2 sub-spectra; Stripping abnormal noise spectrum in multiple candidate nuclear magnetic resonance logging T2 sub-spectra to obtain multiple nuclear magnetic resonance logging T2 sub-spectra.

3. The method of claim 1, wherein, The nuclear magnetic resonance logging data comprises nuclear magnetic resonance T2 spectrum, and before the data analysis of the nuclear magnetic resonance logging data to obtain corresponding multiple nuclear magnetic resonance logging T2 sub-spectra, the method further comprises: Based on the clay mineral content and the clay mineral content threshold, a clay mineral content difference parameter is determined; Based on the clay mineral content difference parameter, the nuclear magnetic resonance T2 spectrum is standardized. Smooth filtering is performed on the normalized nuclear magnetic resonance T2 spectrum.

4. The method of claim 1, wherein, The multiple nuclear magnetic resonance logging T2 sub-spectra include: Clay bound fluid spectrum, capillary bound fluid spectrum, mesopore movable fluid spectrum, and macropore movable fluid spectrum.

5. An apparatus for determining shale pore fluid type and porosity, comprising: The shale pore fluid type and porosity determination device is used to perform the shale pore fluid type and porosity determination method of any one of claims 1-4, and includes: An acquisition module is configured to acquire nuclear magnetic resonance logging data of shale in a target interval, and perform T2 spectrum component stripping processing on the nuclear magnetic resonance logging data to obtain corresponding multiple nuclear magnetic resonance logging T2 sub-spectra. A processing module is configured to perform fluid type calibration on the multiple nuclear magnetic resonance logging T2 sub-spectra using pore fluid type calibration features to obtain a fluid type corresponding to each nuclear magnetic resonance logging T2 sub-spectrum, wherein the pore fluid type calibration features are used to indicate T1-T2 signal interval distributions corresponding to multiple pore fluid types, and the pore fluid type calibration features are determined according to differences in T1-T2 spectrum diagrams under different clay mineral content shale and different core saturation states. The processing module is further configured to determine effective porosity and movable fluid porosity of the shale based on the multiple nuclear magnetic resonance logging T2 sub-spectra and corresponding fluid types.

6. The apparatus of claim 5, wherein: The acquisition module is further configured to acquire compensated neutron logging data and clay mineral content of the shale in the target interval. The processing module is further configured to determine clay mineral structure water content of the target interval based on the target nuclear magnetic resonance sub-data and the compensated neutron logging data, construct a mapping regression relationship based on the clay mineral structure water content and the clay mineral content in the case of core depth homing, and obtain continuous longitudinal shale clay mineral content of the shale; and Perform calibration processing on pore fluid types and corresponding T1-T2 signal interval distributions based on the continuous longitudinal shale clay mineral content to obtain the pore fluid type calibration features.

7. An apparatus for determining shale pore fluid type and porosity, comprising: The device includes: a memory; a processor; wherein the memory stores computer execution instructions; the processor executes the computer execution instructions stored in the memory to implement the method of any one of claims 1-4.

8. A computer storage medium, characterized in that, The computer storage medium stores computer execution instructions, and the computer execution instructions are executed by the processor to implement the method of any one of claims 1-4.

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