Shale reservoir fluid fluidity and productivity characterization method, device, equipment and medium

Abstract

The invention discloses a shale reservoir fluid fluidity and productivity characterization method, device and equipment and a medium, and relates to the technical field of oil and gas field exploration and development, nuclear magnetic resonance T1-T2 experimental measurement and inversion are performed on a core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and the T1 value and T2 value of each spectrum peak in the nuclear magnetic resonance T1-T2 spectrum are determined; constructing an inversion objective function based on the T1 value and the T2 value by using a nuclear magnetic resonance relaxation theory model, and solving the objective function to obtain the optimal translational diffusion correlation time of each spectrum peak; determining a fluid type corresponding to each spectrum peak based on the optimal translation diffusion correlation time; calculating the average translational diffusion correlation time and saturation of each single-phase fluid; carrying out shale reservoir fluid fluidity characterization on the core sample by utilizing the average translational diffusion correlation time of each single-phase fluid; the productivity index is calculated, shale reservoir productivity characterization is carried out on the core sample, and rapid, accurate and non-destructive characterization of the oil phase and water phase flowability and productivity of the shale reservoir is achieved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field exploration and development, and in particular to a method, device, equipment and medium for characterizing the fluidity and productivity of shale reservoir fluids. Background Art

[0002] Reservoir fluid mobility is a key parameter in assessing the value of shale oil and gas development. Currently, common methods for characterizing reservoir fluid mobility have significant limitations. Rock pyrolysis evaluates fluid mobility by measuring the volatilization of hydrocarbons at different temperature ranges, but this method suffers from issues such as loss of light hydrocarbons and significant influence from sample heterogeneity. While solvent extraction can distinguish components of different polarities, the experimental process is cumbersome and damages the sample's pristine state. Nuclear magnetic resonance (NMR) is a powerful technique for directly detecting fluid signals, offering advantages such as rapid measurement, wide observational coverage, and in situ characterization. However, its results are subject to interference from factors such as the surface properties and pore structure of the porous medium. Reservoir productivity characterization is also crucial for shale oil and gas development decisions. Shale reservoirs are characterized by low permeability, complex pore structures, and strong heterogeneity. Traditional productivity evaluation methods based on reservoir physical parameters are no longer applicable in these reservoirs. The actual productivity of shale reservoirs is primarily determined by the fluid's inherent flow capacity and content, but research and mature methods for characterizing productivity specifically addressing these characteristics are currently lacking.

[0003] As can be seen from the above, how to directly extract fluid characteristic information from NMR measurement results, avoid the influence of interfering factors such as the surface properties and pore structure of the porous medium, and achieve rapid, accurate and non-destructive characterization of the fluidity and productivity of the oil and water phases in shale reservoirs, and further comprehensively consider the influence of fluid saturation to establish a productivity characterization method tailored to the characteristics of shale reservoirs are problems to be solved in this field. Summary of the Invention

[0004] In view of this, the present invention aims to provide a method, apparatus, device, and medium for characterizing the fluidity and productivity of shale reservoir fluids. These methods are capable of rapidly, accurately, and non-destructively characterizing the fluidity and productivity of the oil and water phases in shale reservoirs, without being affected by interfering factors such as the surface properties and pore structure of the porous medium. The specific scheme is as follows:

[0005] In a first aspect, the present application discloses a method for characterizing the fluid mobility and productivity of a shale reservoir, comprising:

[0006] Performing nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and determining the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum;

[0007] Using a nuclear magnetic resonance relaxation theory model and based on the T1 value and T2 value, an inversion objective function is constructed, and the objective function is solved to obtain the optimal translational diffusion correlation time of each spectral peak;

[0008] determining the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time;

[0009] Calculate the average translational diffusion correlation time and saturation of each single-phase fluid;

[0010] Characterizing the fluidity of shale reservoir fluids on the core sample using the average translational diffusion correlation time of each single-phase fluid;

[0011] Calculating a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time;

[0012] The productivity index of each single-phase fluid is used to characterize the shale reservoir productivity of the core sample.

[0013] Optionally, performing nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum includes:

[0014] Conduct nuclear magnetic resonance T1-T2 experimental measurements on core samples to obtain echo data;

[0015] The echo data are inverted to obtain a nuclear magnetic resonance T1-T2 spectrum.

[0016] Optionally, the method of using a nuclear magnetic resonance relaxation theory model and constructing an inversion objective function based on the T1 value and the T2 value, solving the objective function, and obtaining the optimal translational diffusion correlation time of each spectral peak includes:

[0017] Determining the theoretical relationship between the T1 and T2 values and the translational diffusion time of fluid molecules based on a nuclear magnetic resonance relaxation theory model;

[0018] Simplifying and generalizing the theoretical relationship to obtain the inversion objective function;

[0019] Solve the objective function and use a preset inversion algorithm to solve the optimal translational diffusion correlation time of each spectral peak; the preset inversion algorithm includes an optimization algorithm such as gradient descent method, Newton method, grid search method, simulated annealing method, etc.

[0020] Optionally, the NMR relaxation theoretical model is a theoretical expression of relaxation times T1 and T2 with respect to translational diffusion correlation time; the theoretical expression is:

[0021] ;

[0022] ;

[0023] Among them, C is a parameter item related to physical constants, surface property parameters of porous media and pore structure property parameters, is the spectral density function of the fluid surface relaxation, is the translational diffusion correlation time of fluid molecules, is the surface residence time of fluid molecules;

[0024] The inversion objective function is:

[0025] ;

[0026] in, is the inversion objective function, measured and calculated are the subscripts of the experimental measurement value and the theoretical calculation value respectively;

[0027] The inversion objective function is solved as follows:

[0028] .

[0029] Optionally, determining the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time includes:

[0030] The fluid type corresponding to each spectral peak is determined based on the theoretical range of different types of fluids under experimental temperature and pressure conditions and the optimal translational diffusion correlation time; the fluid types include single-phase oil, oil-water miscible phase, single-phase water, gas-liquid miscible phase, and single-phase gas.

[0031] Optionally, the calculating of the average translational diffusion correlation time and saturation of each single-phase fluid includes:

[0032] Calculate the signal amplitude of each peak in the NMR T1-T2 spectrum and the sum of the signal amplitudes of all fluid peaks;

[0033] Calculate the sum of the signal amplitudes of each single-phase fluid;

[0034] Calculate the average translational diffusion correlation time and saturation of each single-phase fluid;

[0035] The signal amplitude and calculation formula of single-phase fluid f are:

[0036] ;

[0037] in, is the signal amplitude of the spectrum peak i whose spectrum peak type is determined to be f, is the signal amplitude and of the single-phase fluid f;

[0038] The calculation formula for the average translational diffusion correlation time is:

[0039] ;

[0040] in, is the average translational diffusion correlation time of the single-phase fluid f;

[0041] The saturation calculation formula of the single-phase fluid is:

[0042] ;

[0043] in, is the saturation of the single-phase fluid f, is the sum of the signal amplitudes of all fluid spectral peaks.

[0044] Optionally, the utilizing the productivity index of each single-phase fluid to characterize the shale reservoir productivity of the core sample includes:

[0045] The productivity index is obtained by calculating the saturation and the average translational diffusion correlation time using the productivity index calculation formula;

[0046] The production capacity index calculation formula is:

[0047] ;

[0048] in, is the capacity index.

[0049] In a second aspect, the present application discloses a shale reservoir fluid mobility and productivity characterization device, comprising:

[0050] The sample measurement module is used to perform nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum and determine the T1 value and T2 value of each peak in the nuclear magnetic resonance T1-T2 spectrum;

[0051] An objective function solving module is used to construct an inversion objective function based on the T1 value and the T2 value using a nuclear magnetic resonance relaxation theory model, solve the objective function, and obtain the optimal translational diffusion correlation time of each spectral peak;

[0052] a fluid type determination module, configured to determine the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time;

[0053] Saturation calculation module, used to calculate the average translational diffusion correlation time and saturation of each single-phase fluid;

[0054] a fluidity characterization module, configured to characterize the fluidity of the shale reservoir fluid on the core sample using the average translational diffusion correlation time of each single-phase fluid;

[0055] a productivity index calculation module, configured to calculate a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time;

[0056] The productivity characterization module is used to characterize the shale reservoir productivity of the core sample by using the productivity index of each single-phase fluid.

[0057] In a third aspect, the present application discloses an electronic device, comprising:

[0058] Memory, used to store computer programs;

[0059] A processor is used to execute the computer program to implement the aforementioned shale reservoir fluid mobility and productivity characterization method.

[0060] In a fourth aspect, the present application discloses a computer storage medium for storing a computer program; wherein, when the computer program is executed by a processor, the steps of the aforementioned disclosed method for characterizing the fluid mobility and productivity of shale reservoir fluids are implemented.

[0061] It can be seen that the present application provides a method for characterizing the fluidity and productivity of shale reservoir fluids, including performing nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on a core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, determining the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum; using a nuclear magnetic resonance relaxation theory model and constructing an inversion objective function based on the T1 value and T2 value, solving the objective function, and obtaining the optimal translational diffusion correlation time of each spectral peak; determining the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time; calculating the average translational diffusion correlation time and saturation of each single-phase fluid; using the average translational diffusion correlation time of each single-phase fluid to characterize the fluidity of the shale reservoir fluids on the core sample; calculating a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time; and using the productivity index of each single-phase fluid to characterize the productivity of the shale reservoir on the core sample. This application first performs nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain the nuclear magnetic resonance T1-T2 spectrum, determine the T1 value and T2 value of each spectral peak, and then use the nuclear magnetic resonance relaxation theory model to construct the inversion objective function, solve the optimal translational diffusion correlation time of each spectral peak, determine the fluid type corresponding to each spectral peak, calculate the average translational diffusion correlation time and saturation of each single-phase fluid, and use the average translational diffusion correlation time of each single-phase fluid to characterize the fluidity of different fluids in the shale reservoir. The saturation of each single-phase fluid and the average translational diffusion correlation time are used to calculate the productivity index; the productivity index of each single-phase fluid can be used to characterize the productivity of the shale reservoir. This application can directly extract fluid characteristic information from the nuclear magnetic resonance response characteristics, without being affected by interfering factors such as the surface properties of the porous medium and the pore structure, and realize rapid, accurate and non-destructive characterization of the fluidity and productivity of the oil and water phases in the shale reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0062] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are merely embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on the provided drawings without paying any creative work.

[0063] Figure 1 This is a flow chart of a method for characterizing shale reservoir fluid mobility and productivity disclosed in this application;

[0064] Figure 2 A specific flow chart for characterizing shale reservoir fluid mobility and productivity disclosed in this application;

[0065] Figure 3 This is an example diagram of a T1-T2 spectrum result disclosed in this application;

[0066] Figure 4 This is a schematic diagram of the structure of a shale reservoir fluid mobility and productivity characterization device disclosed in this application;

[0067] Figure 5 This is a structural diagram of an electronic device provided in this application. DETAILED DESCRIPTION

[0068] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0069] Reservoir fluid mobility is a key parameter in assessing the value of shale oil and gas development. Currently, common methods for characterizing reservoir fluid mobility have significant limitations. Rock pyrolysis evaluates fluid mobility by measuring the volatilization of hydrocarbons at different temperature ranges, but this method suffers from issues such as loss of light hydrocarbons and significant influence from sample heterogeneity. While solvent extraction can distinguish components of different polarities, the experimental process is cumbersome and damages the sample's pristine state. Nuclear magnetic resonance (NMR) is a powerful technique for directly detecting fluid signals, offering advantages such as rapid measurement, wide observational coverage, and in situ characterization. However, its results are subject to interference from factors such as the surface properties and pore structure of the porous medium. Reservoir productivity characterization is also crucial for shale oil and gas development decisions. Shale reservoirs are characterized by low permeability, complex pore structures, and strong heterogeneity. Traditional productivity evaluation methods based on reservoir physical parameters are no longer applicable in these reservoirs. The actual productivity of shale reservoirs is primarily determined by the fluid's inherent flow capacity and content, but research and mature methods for characterizing productivity specifically addressing these characteristics are currently lacking. As can be seen from the above, how to directly extract fluid characteristic information from NMR measurement results, avoid the influence of interfering factors such as the surface properties and pore structure of the porous medium, and achieve rapid, accurate and non-destructive characterization of the fluidity and productivity of the oil and water phases in shale reservoirs, and further comprehensively consider the influence of fluid saturation to establish a productivity characterization method tailored to the characteristics of shale reservoirs are problems to be solved in this field.

[0070] See also Figure 1 As shown, the embodiment of the present invention discloses a method for characterizing the fluidity and productivity of shale reservoir fluids, which may specifically include:

[0071] Step S11: performing nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and determining the T1 value and T2 value of each peak in the nuclear magnetic resonance T1-T2 spectrum.

[0072] In this embodiment, a nuclear magnetic resonance T1-T2 experimental measurement is performed on the core sample to obtain echo data, the echo data is inverted to obtain a nuclear magnetic resonance T1-T2 spectrum, and the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum are determined.

[0073] Step S12: constructing an inversion objective function based on the T1 value and the T2 value using a nuclear magnetic resonance relaxation theory model, solving the objective function, and obtaining the optimal translational diffusion correlation time of each spectral peak.

[0074] In this embodiment, based on the nuclear magnetic resonance relaxation theory model, the theoretical relationship between the T1 value and the T2 value and the fluid molecule translational diffusion correlation time is determined; the theoretical relationship is summarized and simplified to obtain an inversion objective function; the objective function is solved, and the optimal translational diffusion correlation time of each spectral peak is solved using a preset inversion algorithm; the preset inversion algorithm includes optimization algorithms such as gradient descent method, Newton method, grid search method, simulated annealing method, etc.

[0075] That is, this application is based on the NMR relaxation theory model to determine the correlation time between the NMR T1 and T2 responses and the translational diffusion of fluid molecules. The theoretical relationship is summarized and simplified to obtain the solution The inversion objective function is used to determine the value or value range of each parameter in the nuclear magnetic resonance relaxation theory model, and the optimal translational diffusion correlation time of each spectral peak is solved using a preset inversion algorithm. , so that the error calculation result of the objective function is minimized.

[0076] The NMR relaxation theory model in this application is a theoretical expression of the relaxation times T1 and T2 with respect to the translational diffusion correlation time; the theoretical expression is:

[0077] ;

[0078] ;

[0079] Among them, C is a parameter item related to physical constants, surface property parameters of porous media and pore structure property parameters, is the spectral density function of the fluid surface relaxation, is the translational diffusion correlation time of fluid molecules, is the surface residence time of fluid molecules;

[0080] The inversion objective function is:

[0081] ;

[0082] in, is the inversion objective function, measured and calculated are the subscripts of the experimental measurement value and the theoretical calculation value respectively;

[0083] The inversion objective function is solved as follows:

[0084] .

[0085] Step S13: determining the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time.

[0086] In this embodiment, the fluid type corresponding to each spectral peak is determined based on the theoretical range of different types of fluids under experimental temperature and pressure conditions and the optimal translational diffusion correlation time; the fluid types include single-phase oil, oil-water miscible phase, single-phase water, gas-liquid miscible phase, and single-phase gas.

[0087] Specifically, according to the experimental temperature and pressure conditions, different types of fluids Theoretical range, determine the fluid type corresponding to each spectral peak, wherein, under normal temperature and pressure conditions, the different types of fluids The theoretical range can be determined from the Einstein-Smoluchowski diffusion equation:

[0088] Single-phase oil: 2.75ns≤ <108.38ns;

[0089] Oil-water miscible phase: 99.84ps≤ <2.75ns;

[0090] Single-phase water: 9.00ps≤ <99.84ps;

[0091] Gas-liquid miscibility: 2.00ps≤ <9.00ps;

[0092] Single-phase gas: 0.20ps≤ <2.00ps;

[0093] Among them, when the experimental temperature and pressure conditions change significantly, the different types of fluids The theoretical scope needs to be redefined based on the Einstein-Smoluchowski equation.

[0094] Among them, gas-liquid miscible phases include gas-oil miscible phases and gas-water miscible phases.

[0095] Step S14: Calculate the average translational diffusion correlation time and saturation of each single-phase fluid.

[0096] In this embodiment, the signal amplitude of each peak in the nuclear magnetic resonance T1-T2 spectrum and the sum of the signal amplitudes of all fluid peaks are calculated; the sum of the signal amplitudes of each single-phase fluid is calculated; and the average translational diffusion correlation time of each single-phase fluid is calculated;

[0097] The signal amplitude and calculation formula of single-phase fluid f are:

[0098] ;

[0099] in, is the signal amplitude of the spectrum peak i whose spectrum peak type is determined to be f, is the signal amplitude and of the single-phase fluid f;

[0100] The calculation formula for the average translational diffusion correlation time is:

[0101] ;

[0102] in, is the average translational diffusion correlation time of the single-phase fluid f.

[0103] The saturation calculation formula of the single-phase fluid is:

[0104] ;

[0105] in, is the saturation of the single-phase fluid f, is the sum of the signal amplitudes of all fluid spectral peaks.

[0106] Step S15: using the average translational diffusion correlation time of each single-phase fluid to characterize the fluidity of the shale reservoir fluid on the core sample.

[0107] Among them, the smaller the value of the average translational diffusion correlation time of the fluid, the stronger the fluid mobility of the shale reservoir.

[0108] Step S16: Calculating a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time.

[0109] In this embodiment, the productivity index is calculated using the productivity index calculation formula to calculate the saturation and the average translational diffusion correlation time to obtain the productivity index;

[0110] The production capacity index calculation formula is:

[0111] ;

[0112] in, is the capacity index, The unit is decimal, The unit is ps.

[0113] Step S17: using the productivity index of each single-phase fluid to characterize the shale reservoir productivity of the core sample.

[0114] Among them, the smaller the value of the productivity index, the lower the productivity of the shale reservoir.

[0115] The specific process of realizing the characterization of shale reservoir fluid mobility and productivity in this application is as follows: Figure 2 As shown, the core sample is subjected to nuclear magnetic resonance T1-T2 experimental measurement and inversion processing to obtain the nuclear magnetic resonance T1-T2 spectrum of the sample, and the T1 and T2 values of each peak in the nuclear magnetic resonance T1-T2 spectrum are determined and output; based on the nuclear magnetic resonance relaxation theoretical model, the T1 and T2 values are determined to be related to the translational diffusion time of the fluid molecules. The theoretical relationship is established, the inversion objective function is constructed, and the optimal translational diffusion correlation time of each spectral peak is solved using the preset inversion algorithm. ; According to the different types of fluids under experimental temperature and pressure conditions Within the theoretical range, the fluid type corresponding to each spectral peak is determined, and the average translational diffusion correlation time and saturation of each single-phase fluid are calculated. The average translational diffusion correlation time of each single-phase fluid is used to characterize the fluid flow of shale reservoir core samples. The saturation of each single-phase fluid and the average translational diffusion correlation time are used to calculate the productivity index; the productivity of the shale reservoir core samples is then characterized using the productivity index of each single-phase fluid. Fluid characteristic information is directly extracted from the NMR response characteristics, unaffected by interfering factors such as the surface properties and pore structure of the porous medium, enabling rapid, accurate, and non-destructive characterization of the fluidity and productivity of the oil and water phases in shale reservoirs.

[0116] For example, two shale samples were subjected to two-dimensional nuclear magnetic resonance (NMR) T1-T2 measurements on a MesoMR23-060H-I (Mesoscale NMR Analysis and Imaging System) instrument, operating at a center frequency of 21.36 MHz and a temperature of approximately 25°C. The samples were measured using an IR-CPMG (Inversion Recovery-Carr-Purcell Meiboom-Gill) pulse sequence, with the following measurement parameters:

[0117] The waiting time TW was varied from 0.058ms to 2500ms in a logarithmic form, including 25 different waiting times, the echo interval TE was 0.0985ms, the number of echoes was 500, and the number of scans was 128. The BRD (Butler-Reeds-Dawson, nuclear magnetic resonance data inversion) algorithm was used to invert the obtained Spectrum, The spectrum results are as follows: Figure 3 shown.

[0118] Two shale samples The T1 and T2 values corresponding to different peaks in the spectrum are shown in Table 1.

[0119] Table 1

[0120]

[0121] Based on the nuclear magnetic resonance relaxation theoretical model, the theoretical relationship with the time associated with the translational diffusion of fluid molecules is determined. The theoretical relationship is summarized and simplified, and then the objective function is solved to determine the values or value ranges of various parameters in the nuclear magnetic resonance relaxation theoretical model. The values or value ranges of various parameters are shown in Table 2.

[0122] Table 2

[0123]

[0124] The optimal translational diffusion correlation time of each spectral peak is solved using a preset inversion algorithm so that the error calculation result of the objective function is minimized. The solution results are shown in Table 3.

[0125] Table 3

[0126]

[0127] Based on the theoretical range of different types of fluids under the experimental temperature and pressure conditions, the fluid type corresponding to each spectral peak was determined. In sample #58, peak A was solid organic matter, peaks B, C, and D were all single-phase oil, peak E was an oil-water miscible phase, and peaks F and G were both single-phase water. In sample #65, peak A was solid organic matter, peaks B, C, and D were all single-phase oil, peak E was an oil-water miscible phase, and peaks F and G were both single-phase water.

[0128] The signal amplitudes of each spectrum peak are calculated as shown in Table 3.

[0129] The average translational diffusion correlation time, saturation and fluidity index of the oil phase and water phase in the sample are calculated and shown in Table 4.

[0130] Table 4

[0131]

[0132] Among them, in sample #58, the signal amplitude of the single-phase oil is 368.56, and the average translational diffusion correlation time is 22.81 ps, the signal amplitude of single-phase water is 345.54, and the average translational diffusion correlation time is For sample #65, the signal amplitude of the single-phase oil is 352.38, and the average translational diffusion correlation time is 17.95 ps, the signal amplitude of single-phase water is 348.72, and the average translational diffusion correlation time is is 58ps; in sample #58, the saturation of the single-phase oil S o The saturation of single-phase water is S w is 48.38%, and the productivity index PI is 0.26; in sample #65, the saturation of single-phase oil S o is 50.26%, the capacity index PI is 0.12, and the saturation of single-phase water S w The oil and gas production capacity is 49.73%, and the productivity index (PI) is 0.28. The subscripts o and w represent single-phase oil and single-phase water, respectively.

[0133] In addition, those skilled in the art will appreciate that the present application is not only applicable to shale reservoirs, but also to various types of reservoirs, such as sandstone reservoirs, carbonate reservoirs, volcanic reservoirs, etc., without limitation herein.

[0134] In this embodiment, nuclear magnetic resonance T1-T2 experimental measurement and inversion processing are performed on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum are determined; a nuclear magnetic resonance relaxation theoretical model is used and an inversion objective function is constructed based on the T1 value and T2 value, and the objective function is solved to obtain the optimal translational diffusion correlation time of each spectral peak; the fluid type corresponding to each spectral peak is determined based on the optimal translational diffusion correlation time; the average translational diffusion correlation time and saturation of each single-phase fluid are calculated; the reservoir fluidity of the core sample is characterized by using the average translational diffusion correlation time of each single-phase fluid; the productivity index of each single-phase fluid is used to calculate the productivity of the shale reservoir of the core sample. This application first performs nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain the nuclear magnetic resonance T1-T2 spectrum, determine the T1 value and T2 value of each spectral peak, and then use the nuclear magnetic resonance relaxation theory model to construct the inversion objective function, solve the optimal translational diffusion correlation time of each spectral peak, determine the fluid type corresponding to each spectral peak, calculate the average translational diffusion correlation time and saturation of each single-phase fluid, and use the average translational diffusion correlation time of each single-phase fluid to characterize the fluidity of different fluids in the shale reservoir. The saturation of each single-phase fluid and the average translational diffusion correlation time are used to calculate the productivity index; the productivity index of each single-phase fluid can be used to characterize the productivity of the shale reservoir. This application can directly extract fluid characteristic information from the nuclear magnetic resonance response characteristics, without being affected by interfering factors such as the surface properties of the porous medium and the pore structure, and realize rapid, accurate and non-destructive characterization of the fluidity and productivity of the oil and water phases in the shale reservoir.

[0135] See also Figure 4 As shown, the embodiment of the present invention discloses a shale reservoir fluid flow and productivity characterization device, which may specifically include:

[0136] The sample measurement module 11 is used to perform nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum and determine the T1 value and T2 value of each peak in the nuclear magnetic resonance T1-T2 spectrum;

[0137] An objective function solving module 12 is configured to construct an inversion objective function based on the T1 value and the T2 value using a nuclear magnetic resonance relaxation theory model, solve the objective function, and obtain the optimal translational diffusion correlation time of each spectral peak;

[0138] a fluid type determination module 13, configured to determine the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time;

[0139] Saturation calculation module 14, used to calculate the average translational diffusion correlation time and saturation of each single-phase fluid;

[0140] a fluidity characterization module 15, configured to characterize the fluidity of the shale reservoir fluid on the core sample using the average translational diffusion correlation time of each single-phase fluid;

[0141] A productivity index calculation module 16 is configured to calculate a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time;

[0142] The productivity characterization module 17 is configured to characterize the shale reservoir productivity of the core sample using the productivity index of each single-phase fluid.

[0143] In this embodiment, nuclear magnetic resonance T1-T2 experimental measurement and inversion processing are performed on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum are determined; a nuclear magnetic resonance relaxation theoretical model is used and an inversion objective function is constructed based on the T1 value and T2 value, and the objective function is solved to obtain the optimal translational diffusion correlation time of each spectral peak; the fluid type corresponding to each spectral peak is determined based on the optimal translational diffusion correlation time; the average translational diffusion correlation time and saturation of each single-phase fluid are calculated; the core sample is used to characterize the fluidity of the shale reservoir fluid using the average translational diffusion correlation time of each single-phase fluid; the productivity index of each single-phase fluid is used to calculate the productivity of the shale reservoir of the core sample. This application first performs nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain the nuclear magnetic resonance T1-T2 spectrum, determines the T1 value and T2 value of each spectral peak, and then uses the nuclear magnetic resonance relaxation theory model to construct the inversion objective function, solves the optimal translational diffusion correlation time of each spectral peak, determines the fluid type corresponding to each spectral peak, and calculates the average translational diffusion correlation time of each single-phase fluid. The average translational diffusion correlation time of each single-phase fluid can be used to characterize the fluidity of different fluids in the shale reservoir, and the saturation of each single-phase fluid and the average translational diffusion correlation time are used to calculate the productivity index; the productivity of the shale reservoir can be characterized by the productivity index of each single-phase fluid. This application can directly extract fluid characteristic information from the nuclear magnetic resonance response characteristics, without being affected by interfering factors such as the surface properties of the porous medium and the pore structure, thereby achieving rapid, accurate and non-destructive characterization of the fluidity and productivity of the oil phase and water phase of the shale reservoir.

[0144] In some specific embodiments, the sample measurement module 11 may specifically include:

[0145] Experimental measurement module, used to perform nuclear magnetic resonance T1-T2 experimental measurement on core samples to obtain echo data;

[0146] The echo data inversion module is used to invert the echo data to obtain a nuclear magnetic resonance T1-T2 spectrum.

[0147] In some specific embodiments, the objective function solving module 12 may specifically include:

[0148] A theoretical relationship determination module, configured to determine the theoretical relationship between the T1 value and the T2 value and the time associated with the translational diffusion of fluid molecules based on a nuclear magnetic resonance relaxation theory model;

[0149] An induction and simplification module, used for summarizing and simplifying the theoretical relationship to obtain an inversion objective function;

[0150] The solution module is used to solve the objective function and use a preset inversion algorithm to solve the optimal translational diffusion correlation time of each spectral peak; the preset inversion algorithm includes an optimization algorithm such as gradient descent method, Newton method, grid search method, simulated annealing method, etc.

[0151] In some specific embodiments, the NMR relaxation theoretical model is a theoretical expression of relaxation times T1 and T2 with respect to translational diffusion correlation time; the theoretical expression is:

[0152] ;

[0153] ;

[0154] Among them, C is a parameter item related to physical constants, surface property parameters of porous media and pore structure property parameters, is the spectral density function of the fluid surface relaxation, is the translational diffusion correlation time of fluid molecules, is the surface residence time of fluid molecules;

[0155] The inversion objective function is:

[0156] ;

[0157] in, is the inversion objective function, measured and calculated are the subscripts of the experimental measurement value and the theoretical calculation value respectively;

[0158] The inversion objective function is solved as follows:

[0159] .

[0160] In some specific embodiments, the fluid type determination module 13 may specifically include:

[0161] The fluid type determination module is used to determine the fluid type corresponding to each spectral peak based on the theoretical range of different types of fluids under experimental temperature and pressure conditions and the optimal translational diffusion correlation time; the fluid types include single-phase oil, oil-water miscible phase, single-phase water, gas-liquid miscible phase, and single-phase gas.

[0162] In some specific embodiments, the saturation calculation module 14 may specifically include:

[0163] A signal amplitude calculation module for spectrum peaks and a signal amplitude sum calculation module, used to calculate the signal amplitude of each spectrum peak in the nuclear magnetic resonance T1-T2 spectrum and the signal amplitude sum of all fluid spectrum peaks;

[0164] A single-phase fluid signal amplitude sum calculation module, used to calculate the signal amplitude sum of each single-phase fluid;

[0165] The average translational diffusion correlation time calculation module of the single-phase fluid is used to calculate the average translational diffusion correlation time of each single-phase fluid;

[0166] The signal amplitude and calculation formula of single-phase fluid f are:

[0167] ;

[0168] in, is the signal amplitude of the spectrum peak i whose spectrum peak type is determined to be f, is the signal amplitude and of the single-phase fluid f;

[0169] The calculation formula for the average translational diffusion correlation time is:

[0170] ;

[0171] in, is the average translational diffusion correlation time of the single-phase fluid f;

[0172] The saturation calculation formula of the single-phase fluid is:

[0173] ;

[0174] in, is the saturation of the single-phase fluid f, is the sum of the signal amplitudes of all fluid spectral peaks.

[0175] In some specific embodiments, the capacity characterization module 16 may specifically include:

[0176] A capacity index calculation module is used to calculate the saturation and the average translational diffusion correlation time using the capacity index calculation formula to obtain the capacity index;

[0177] The production capacity index calculation formula is:

[0178] ;

[0179] in, is the capacity index.

[0180] Figure 5 This is a schematic diagram of the structure of an electronic device provided in an embodiment of the present application. The electronic device 20 may include: at least one processor 21, at least one memory 22, a power supply 23, a communication interface 24, an input / output interface 25, and a communication bus 26. The memory 22 is used to store a computer program, which is loaded and executed by the processor 21 to implement the relevant steps of the shale reservoir fluid mobility and productivity characterization method performed by the electronic device as disclosed in any of the aforementioned embodiments.

[0181] In this embodiment, the power supply 23 is used to provide operating voltage for each hardware device on the electronic device 20; the communication interface 24 can create a data transmission channel between the electronic device 20 and the external device. The communication protocol it follows is any communication protocol that can be applied to the technical solution of this application and is not specifically limited here; the input and output interface 25 is used to obtain external input data or output data to the outside world. Its specific interface type can be selected according to specific application needs and is not specifically limited here.

[0182] In addition, the memory 22, as a carrier for resource storage, can be a read-only memory, random access memory, disk or CD, etc. The resources stored thereon include an operating system 221, a computer program 222 and data 223, etc. The storage method can be temporary storage or permanent storage.

[0183] The operating system 221 is used to manage and control the hardware devices and computer program 222 on the electronic device 20, enabling the processor 21 to calculate and process data 223 in the memory 22. It can be run under Windows, Unix, Linux, or other operating systems. In addition to computer programs capable of implementing the shale reservoir fluid flow and productivity characterization method performed by the electronic device 20 as disclosed in any of the aforementioned embodiments, the computer program 222 may also include computer programs capable of performing other specific tasks. Data 223 may include data transmitted from external devices to the shale reservoir fluid flow and productivity characterization device, as well as data collected by its own input / output interface 25.

[0184] The steps of the methods or algorithms described in conjunction with the embodiments disclosed herein may be implemented directly using hardware, a software module executed by a processor, or a combination of the two. The software module may be placed in random access memory (RAM), internal memory, read-only memory (ROM), electrically programmable ROM, electrically erasable programmable ROM, registers, a hard disk, a removable disk, a CD-ROM, or any other form of storage medium known in the art.

[0185] Furthermore, an embodiment of the present application also discloses a computer-readable storage medium, in which a computer program is stored. When the computer program is loaded and executed by a processor, the steps of the shale reservoir fluid fluidity and productivity characterization method disclosed in any of the aforementioned embodiments are implemented.

[0186] Finally, it should be noted that, in this document, relational terms such as first and second, etc., are used only to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any actual relationship or order between these entities or operations. Moreover, the terms "comprises," "comprising," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or device comprising a series of elements includes not only those elements, but also other elements not explicitly listed, or elements inherent to such process, method, article, or device. In the absence of further limitations, an element defined by the phrase "comprising a ..." does not exclude the presence of additional identical elements in the process, method, article, or device comprising the element.

[0187] The above is a detailed introduction to the method, device, equipment and storage medium for characterizing the fluid flow and productivity of shale reservoirs provided by the present invention. Specific examples are used herein to illustrate the principles and implementation methods of the present invention. The description of the above embodiments is only used to help understand the method of the present invention and its core ideas. At the same time, for those skilled in the art, according to the ideas of the present invention, there will be changes in the specific implementation methods and application scopes. In summary, the content of this specification should not be understood as limiting the present invention.

Claims

1. A method for characterizing shale reservoir fluid mobility and productivity, characterized in that: include: Performing nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum, and determining the T1 value and T2 value of each spectral peak in the nuclear magnetic resonance T1-T2 spectrum; Using a nuclear magnetic resonance relaxation theory model and constructing an inversion objective function based on the T1 value and the T2 value, solving the objective function to obtain the optimal translational diffusion correlation time of each spectral peak; determining the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time; Calculate the average translational diffusion correlation time and saturation of each single-phase fluid; Characterizing the fluidity of shale reservoir fluids on the core sample using the average translational diffusion correlation time of each single-phase fluid; Calculating a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time; The productivity index of each single-phase fluid is used to characterize the shale reservoir productivity of the core sample.

2. The method for characterizing shale reservoir fluid mobility and productivity according to claim 1, characterized in that: The nuclear magnetic resonance T1-T2 experimental measurement and inversion processing of the core sample to obtain the nuclear magnetic resonance T1-T2 spectrum includes: Conduct nuclear magnetic resonance T1-T2 experimental measurements on core samples to obtain echo data; The echo data are inverted to obtain a nuclear magnetic resonance T1-T2 spectrum.

3. The method for characterizing shale reservoir fluid mobility and productivity according to claim 1, characterized in that: The method utilizes a nuclear magnetic resonance relaxation theory model and constructs an inversion objective function based on the T1 value and the T2 value, solves the objective function, and obtains the optimal translational diffusion correlation time of each spectral peak, including: Determining the theoretical relationship between the T1 and T2 values and the translational diffusion time of fluid molecules based on a nuclear magnetic resonance relaxation theory model; Simplifying and generalizing the theoretical relationship to obtain the inversion objective function; Solve the objective function and use a preset inversion algorithm to solve the optimal translational diffusion correlation time of each spectral peak; the preset inversion algorithm includes an optimization algorithm such as gradient descent method, Newton method, grid search method, simulated annealing method, etc.

4. The method for characterizing shale reservoir fluid mobility and productivity according to claim 1, characterized in that: The NMR relaxation theory model is a theoretical expression of the relaxation times T1 and T2 with respect to the translational diffusion correlation time; the theoretical expression is: ； ； Among them, C is a parameter item related to physical constants, surface property parameters of porous media and pore structure property parameters, is the spectral density function of the fluid surface relaxation, is the translational diffusion correlation time of fluid molecules, is the surface residence time of fluid molecules; The inversion objective function is: ； in, is the inversion objective function, measured and calculated are the subscripts of the experimental measurement value and the theoretical calculation value respectively; The inversion objective function is solved as: 。 5. The method for characterizing shale reservoir fluid mobility and productivity according to claim 1, characterized in that: The determining of the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time includes: The fluid type corresponding to each spectral peak is determined based on the theoretical range of different types of fluids under experimental temperature and pressure conditions and the optimal translational diffusion correlation time; the fluid types include single-phase oil, oil-water miscible phase, single-phase water, gas-liquid miscible phase, and single-phase gas.

6. The method for characterizing shale reservoir fluid mobility and productivity according to claim 1, characterized in that: The calculation of the average translational diffusion correlation time and saturation of each single-phase fluid includes: Calculate the signal amplitude of each peak in the NMR T1-T2 spectrum and the sum of the signal amplitudes of all fluid peaks; Calculate the sum of the signal amplitudes of each single-phase fluid; Calculate the average translational diffusion correlation time and saturation of each single-phase fluid; The signal amplitude and calculation formula of single-phase fluid f are: ； in, is the signal amplitude of the spectrum peak i whose spectrum peak type is determined to be f, is the signal amplitude and of the single-phase fluid f; The calculation formula for the average translational diffusion correlation time is: ； in, is the average translational diffusion correlation time of the single-phase fluid f; The saturation calculation formula of the single-phase fluid is: ； in, is the saturation of the single-phase fluid f, is the sum of the signal amplitudes of all fluid spectral peaks.

7. The method for characterizing shale reservoir fluid mobility and productivity according to any one of claims 1 to 6, characterized in that: The method of using the productivity index of each single-phase fluid to characterize the shale reservoir productivity of the core sample includes: The productivity index is obtained by calculating the saturation and the average translational diffusion correlation time using the productivity index calculation formula; The production capacity index calculation formula is: ； in, is the capacity index.

8. A shale reservoir fluid mobility and productivity characterization device, characterized by: include: The sample measurement module is used to perform nuclear magnetic resonance T1-T2 experimental measurement and inversion processing on the core sample to obtain a nuclear magnetic resonance T1-T2 spectrum and determine the T1 value and T2 value of each peak in the nuclear magnetic resonance T1-T2 spectrum; An objective function solving module is used to construct an inversion objective function based on the T1 value and the T2 value using a nuclear magnetic resonance relaxation theory model, solve the objective function, and obtain the optimal translational diffusion correlation time of each spectral peak; a fluid type determination module, configured to determine the fluid type corresponding to each spectral peak based on the optimal translational diffusion correlation time; Saturation calculation module, used to calculate the average translational diffusion correlation time and saturation of each single-phase fluid; a fluidity characterization module, configured to characterize the fluidity of the shale reservoir fluid on the core sample using the average translational diffusion correlation time of each single-phase fluid; a productivity index calculation module, configured to calculate a productivity index using the saturation of each single-phase fluid and the average translational diffusion correlation time; The productivity characterization module is used to characterize the shale reservoir productivity of the core sample by using the productivity index of each single-phase fluid.

9. An electronic device, characterized in that: include: Memory, used to store computer programs; A processor, configured to execute the computer program to implement the method for characterizing the fluid mobility and productivity of a shale reservoir as claimed in any one of claims 1 to 7.

10. A computer-readable storage medium, characterized in that Used to store a computer program; wherein, when the computer program is executed by a processor, the method for characterizing the fluid mobility and productivity of a shale reservoir as claimed in any one of claims 1 to 7 is implemented.

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