Quantitative characterization method for occurrence state of fluid in full-size pores of continental facies shale

Abstract

The invention relates to a shale fluid occurrence state, in particular to a continental facies shale full-size pore fluid occurrence state quantitative characterization method which comprises the following steps: acquiring real-time density of hydrocarbon fluid at sampling points in pores to obtain density distribution data; respectively calculating the average density of a single-layer adsorption phase, the average density of the adsorption phase and the average density of a free phase in the pores; calculating the adsorption quantity according to the adsorption quantity per unit area, obtaining the number of adsorption layers, calculating the thickness of the adsorption layers according to the number of the adsorption layers, and calculating the free quantity according to the adsorption quantity per unit area and the thickness of the adsorption layers; calculating an adsorption mass ratio according to the adsorption quantity and the free quantity, and calculating an adsorption volume ratio according to the adsorption mass ratio, the average density of the adsorption phase and the average density of the free phase; utilizing a high-pressure mercury injection experiment and a nuclear magnetic resonance experiment to obtain a core dimension pore size distribution result; therefore, the adsorption state and the free state of the hydrocarbon fluid in the pores are analyzed. And the resource quantity of the hydrocarbon fluid in the shale can be evaluated more accurately.

Description

Technical Field

[0001] The present invention relates to the field of shale fluid occurrence state, and in particular to a method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale. Background Art

[0002] With the development of experimental technology, existing methods such as nuclear magnetic resonance, X-ray micro-tomography and model building can provide information about pore structure and fluid distribution, but they still cannot fully reveal the state of fluid in the pores.

[0003] The patent document of Chinese patent application publication number CN117969365A discloses a method for quantitative characterization of full-size pores in tight reservoirs, comprising: S1: performing micrometer CT scanning on a full-diameter core sample of a tight reservoir to obtain a three-dimensional spatial structure diagram of the rock skeleton and pores, and segmenting pores with a diameter greater than 65 μm;

[0004] S2: Drill a first core cylinder sample with a diameter of 25 mm from the full-diameter core sample, perform micro-nano CT scanning on the first core cylinder sample, obtain a three-dimensional spatial structure diagram of the rock skeleton and pores, and segment out pores with diameters ranging from 15 μm to 65 μm; S3: Drill a second core cylinder sample with a diameter of 2 mm from the first core plunger sample, perform nano CT scanning on the second core cylinder sample, obtain a three-dimensional spatial structure diagram of the rock skeleton and pores, and segment out pores with diameters ranging from 0.5 μm to 15 μm. Pores; S4: Gallium ion beam cutting is performed on the surface of the second core cylindrical sample to obtain a third core sample with a diameter of 0.1 mm, and the third core sample is subjected to electron beam scanning imaging to segment pores with diameters ranging from 2.5 nm to 0.5 μm, which is the lower limit of the effective pore size of the reservoir; S5: Integrate the pore distribution intervals obtained in S1-S4 to obtain the number, average pore size and volume data of pores contained in unit rock volume of each size, and quantitatively characterize the three-dimensional spatial structure information and size distribution of full-size pores in the tight reservoir.

[0005] The proportion of various occurrence states of shale oil in the existing technology remains to be discussed. The highly uneven material composition of shale is one of the main determinants of shale oil occurrence conditions. The interaction between organic matter and inorganic minerals in shale affects the occurrence characteristics of hydrocarbon fluids in the narrow pores of shale, leading to inaccurate judgment of the occurrence state of fluids in the pores. Summary of the invention

[0006] To this end, the present invention provides a quantitative characterization of the fluid occurrence state in full-size pores of continental shale, which can solve the problem of inaccurate judgment of the fluid occurrence state in shale pores by establishing a characterization model of the occurrence state of hydrocarbon fluids in different pore structures.

[0007] To achieve the above-mentioned purpose, the present invention provides a quantitative characterization of the fluid storage state in the full-size pores of continental shale, including:

[0008] Collecting the real-time density of the hydrocarbon fluid at each sampling point in any pore to obtain density distribution data of the hydrocarbon fluid in the pore, respectively calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data, calculating the average density of the adsorption phase according to the average density of the single-layer adsorption phase, and calculating the average density of the free phase according to the density distribution data;

[0009] Calculating the adsorption amount of the fluid in the pore according to the adsorption amount per unit area, obtaining the number of adsorption layers, and calculating the thickness of the adsorption layer according to the number of adsorption layers, so as to calculate the free amount of hydrocarbon fluid in the pore according to the adsorption amount per unit area and the thickness of the adsorption layer;

[0010] Calculating the adsorption mass ratio according to the adsorbed amount and the free amount, and calculating the adsorption volume ratio according to the adsorbed mass ratio, the adsorbed phase average density and the free phase average density;

[0011] Using high-pressure mercury injection experiments and nuclear magnetic resonance experiments, the core-scale pore distribution law is determined, and the adsorption volume ratio is analyzed to obtain the core-scale pore size distribution result;

[0012] According to the core-scale pore size distribution result, the adsorbed state and free state of the hydrocarbon fluid in the core-scale pores are obtained.

[0013] Furthermore, the formula for calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data is:

[0014]

[0015] Among them, m ali is the fluid adsorption mass of the i-th adsorption layer, V ali is the fluid adsorption volume of the i-th adsorption layer, ρ mass is the density of hydrocarbon fluid, in kg / m 3 , A m is the pore specific surface area, in nm 2 , L i is the i-th adsorption layer, where i=1, 2..., n, n>2, L ii is the adsorption layer adjacent to the i-th layer, ρ ali is the average density of the monolayer adsorption phase in the i-th adsorption layer.

[0016] Furthermore, the formula for calculating the average density of the adsorbed phase according to the average density of the monolayer adsorbed phase is:

[0017]

[0018] Among them, ρ a is the average density of the adsorption phase, the unit is kg / m3, n is the total number of adsorption layers, and i=1 is the first adsorption layer.

[0019] Furthermore, the calculation formula of the adsorption capacity per unit area is:

[0020]

[0021] Among them, C a is the adsorption amount per unit area.

[0022] Furthermore, the formula for calculating the adsorption amount of hydrocarbon fluid in the pores is:

[0023] Q a =A p ·(C a +C b );

[0024] Among them, Q a is the adsorption amount, C a and C b is the adsorption per unit area at different positions in the pore wall, in mg / m 2 , A p is the internal surface area of ​​the pores.

[0025] Furthermore, the formula for calculating the average density of the free phase based on the density distribution data is:

[0026]

[0027] Among them, ρ f is the average density of the free phase, V f is the volume of the free phase, m f is the unit fluid free phase mass, V ali is the unit fluid free phase volume, ρ mass is the density of hydrocarbon fluid, in kg / m 3 , A m is the pore specific surface area, in nm 2 , L1 is the position where the free phase of hydrocarbon fluid begins to appear, and L2 is the position where the free phase of hydrocarbon fluid disappears.

[0028] Furthermore, the formula for the thickness of the adsorption layer is:

[0029]

[0030] Where H is the thickness of the adsorption layer, t ai is the single layer adsorption thickness in nm, n is the number of adsorption layers, i=1, 2...n, n>2.

[0031] Furthermore, the calculation formula for the free amount of hydrocarbon fluid in the pores is:

[0032] Q f =ρ f ·V f =ρ f ·A p (d m -2H)

[0033] Among them, Q f is the free amount, d m is the pore diameter in nm, and H is the adsorption layer thickness.

[0034] Furthermore, the calculation formula for calculating the adsorption mass ratio according to the adsorption amount and the free amount is:

[0035]

[0036] Among them, r am is the adsorption mass percentage.

[0037] Furthermore, the calculation formula for calculating the adsorption volume ratio according to the adsorption mass ratio, the adsorption phase average density and the free phase average density is:

[0038]

[0039] Among them, r av is the adsorption volume ratio, V a is the adsorption volume, V p is the volume of total hydrocarbon fluid.

[0040] Furthermore, the process of obtaining the number of adsorption layers includes:

[0041] respectively obtaining the real-time hydrocarbon fluid density of each adsorption layer to be detected, obtaining the difference between the real-time hydrocarbon fluid density and the bulk fluid density, obtaining a real-time density difference, and determining the real-time density difference according to a standard density difference;

[0042] If the real-time hydrocarbon density difference is greater than the standard density difference, the adsorption layer to be detected is determined to be an adsorption layer;

[0043] If the real-time hydrocarbon density difference is less than or equal to the standard density difference, the adsorption layer to be detected is determined to be a non-adsorption layer;

[0044] When all the adsorption layers to be detected are judged, the number of adsorption layers is obtained to obtain the number of adsorption layers.

[0045] Furthermore, the process of the high-pressure mercury injection experiment includes:

[0046] The shale samples are filled with mercury liquid and subjected to oil washing and drying treatment;

[0047] The treated shale sample is placed in a solid expansion agent filled with nitrogen and transferred to a high-pressure mercury injection experimental instrument;

[0048] In the high-pressure mercury injection experimental instrument, low-pressure vacuum degassing treatment is performed, and the experimental mercury injection pressure value is set. Based on the lower limit value of the pore size, mercury is injected according to a preset program to obtain a capillary pressure curve, and the capillary pressure curve reflects the distribution curve of the pore size.

[0049] Furthermore, the process of the nuclear magnetic resonance experiment includes:

[0050] First, the free fluid in the pores of the shale sample is removed, and then the saturated hydrocarbon fluid is treated for testing. Then, the signal of the saturated hydrocarbon fluid is detected using nuclear magnetic resonance, and finally the pore volume of the shale sample is obtained.

[0051] Furthermore, the process of obtaining core-scale pore size distribution results includes:

[0052] The peak values ​​of the distribution curve and the pore volume are compared to determine the distribution law of core-scale pores, and an analysis is performed based on the distribution law and the adsorption volume ratio to obtain the core-scale pore size distribution result.

[0053] Furthermore, according to the core full-size pore size distribution result and the existence state of the hydrocarbon fluid in the pore, the process of determining the adsorption state and free state of the hydrocarbon fluid in the pore includes:

[0054] The existence state of hydrocarbon fluid in shale pores is determined based on the core-scale pore size distribution result and the adsorption mass ratio, the existence state is analyzed, and the adsorption state and free state of the hydrocarbon fluid in the pores are obtained according to the analysis result.

[0055] Compared with the prior art, the beneficial effect of the present invention is that by collecting the density of each sampling point in the pore, the distribution of hydrocarbon fluids in the pore can be more accurately understood, thereby obtaining more accurate pore structure information; by calculating the average density of the single-layer adsorption phase, the average density of the free phase, the adsorption amount and the free amount, the adsorption state and free state of the hydrocarbon fluid in the pore can be quantitatively analyzed, which provides a basis for analyzing the existence state of the fluid in the porous medium; combined with the high-pressure mercury injection experiment and the nuclear magnetic resonance experiment, the core-scale pore distribution law can be determined, thereby obtaining the full-size pore size distribution result, which is helpful for evaluating the pore structure; by analyzing the adsorption mass ratio and the adsorption volume ratio, the adsorption state and free state of the hydrocarbon fluid in the pore can be identified, which provides a basis for predicting the flow and transmission of the fluid in the pore; through the above analysis, the occurrence state of hydrocarbon fluids in the shale pore structure can be more accurately evaluated, which is of great significance for the development of hydrocarbon fluids in shale.

[0056] In particular, calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore through density distribution data is helpful to predict the flow and transmission of fluid in the pores. During the data processing process, this formula can be used to quickly calculate the average density of the single-layer adsorption phase, reducing the complexity and time cost of data processing and improving research efficiency.

[0057] In particular, by calculating the average density of the adsorbed phase, the adsorption performance of hydrocarbon fluids in shale pores can be evaluated. Compared with traditional estimation or rough calculation methods, formula calculations based on density distribution data can significantly reduce errors and improve the reliability and scientificity of the data.

[0058] In particular, by utilizing density distribution data, the average density of the free phase can be accurately calculated, which helps to more accurately reflect the physical state and properties of the free phase and provides important data support for understanding and predicting fluids in pores.

[0059] In particular, the amount of adsorption per unit area can be calculated to intuitively express the amount of fluid adsorption in the pores, which is a key indicator for evaluating adsorption capacity. It helps to determine the adsorption of fluid in pores and improve the accuracy and reliability of predictions.

[0060] In particular, through scientific calculations, the adsorption amount of fluid in shale pores can be evaluated more accurately, providing reliable data support for the development of shale gas resources and helping to serve as an important indicator for studying pore structure and surface properties.

[0061] In particular, by obtaining the real-time fluid density of each adsorption layer to be detected, the timeliness and accuracy of the data can be ensured, thereby more accurately reflecting the state of the adsorption layer. By setting the standard density difference as the basis for judgment, the boundary between the adsorption layer and the non-adsorption layer can be scientifically divided, reducing the judgment error. Based on real-time measurement and comparison of density differences, it is possible to more accurately identify which layers are adsorption layers.

[0062] In particular, the free phase can be quantitatively evaluated through computational methods, and accurate quantification provides data support for the determination of the fluid storage state in the pores, which can reduce uncertainties in the development process and reduce technical risks.

[0063] In particular, through high-pressure mercury injection experiments, the experiment can provide a measurement of porosity, that is, the ratio of pore volume to total volume. According to the capillary pressure curve, the pore size distribution of shale samples can be accurately determined, which is crucial for understanding the pore structure.

[0064] In particular, by removing free fluid and saturating hydrocarbon fluid through the nuclear magnetic resonance experiment, the pore volume of the shale sample is obtained, and the pore structure can be analyzed more accurately.

[0065] In particular, by comparing the peak values ​​of the distribution curve and pore volume, the proportion and distribution of pores of different sizes in the core can be accurately identified, which helps to gain a deeper understanding of the pore structure characteristics of the core. According to the distribution law of pores at the core scale, the development value can be evaluated, thereby improving the recovery rate.

[0066] In particular, determining the adsorbed and free states of the fluid through the core-scale pore size distribution results and the adsorption mass ratio can help optimize the mining strategy, more accurately evaluate the reserves and development potential of shale resources, and reduce uncertainties in the development process. BRIEF DESCRIPTION OF THE DRAWINGS

[0067] Figure 1 A schematic diagram of a process for quantitatively characterizing the fluid storage state in full-size pores of continental shale provided in an embodiment of the present invention;

[0068] Figure 2 A schematic diagram of the process of a high-pressure mercury injection experiment for quantitatively characterizing the state of fluid occurrence in full-size pores of continental shale provided in an embodiment of the present invention;

[0069] Figure 3 A diagram showing the results of a high-pressure mercury injection experiment for quantitatively characterizing the state of fluid occurrence in full-size pores of continental shale provided in an embodiment of the present invention;

[0070] Figure 4 This is a diagram of the occurrence state results for quantitatively characterizing the occurrence state of fluids in full-size pores of continental shale provided in an embodiment of the present invention. DETAILED DESCRIPTION

[0071] In order to make the objects and advantages of the present invention more clearly understood, the present invention is further described below in conjunction with embodiments; it should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.

[0072] The preferred embodiments of the present invention are described below with reference to the accompanying drawings. It should be understood by those skilled in the art that these embodiments are only used to explain the technical principles of the present invention and are not intended to limit the protection scope of the present invention.

[0073] It should be noted that, in the description of the present invention, terms such as "up", "down", "left", "right", "inside" and "outside" indicating directions or positional relationships are based on the directions or positional relationships shown in the drawings. This is merely for the convenience of description and does not indicate or imply that the device or element must have a specific orientation, be constructed and operated in a specific orientation. Therefore, it should not be understood as a limitation on the present invention.

[0074] In addition, it should be noted that in the description of the present invention, unless otherwise clearly specified and limited, the terms "installed", "connected" and "connected" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection or an indirect connection through an intermediate medium, or it can be the internal communication of two components. For those skilled in the art, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0075] See also Figure 1 As shown, the present invention provides a method for quantitatively characterizing the fluid storage state in full-size pores of continental shale, the method comprising:

[0076] Step S100, collecting the real-time density of the hydrocarbon fluid at each sampling point in any pore to obtain density distribution data of the hydrocarbon fluid in the pore, and calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data, so as to calculate the average density of the adsorption phase according to the average density of the single-layer adsorption phase, and calculate the average density of the free phase according to the density distribution data;

[0077] Step S200, calculating the adsorption amount of the fluid in the pore according to the adsorption amount per unit area, obtaining the number of adsorption layers, calculating the thickness of the adsorption layer according to the number of adsorption layers, and calculating the free amount of hydrocarbon fluid in the pore according to the adsorption amount per unit area and the thickness of the adsorption layer;

[0078] Step S300, calculating the adsorption mass ratio according to the adsorption amount and the free amount, and calculating the adsorption volume ratio according to the adsorption mass ratio, the adsorption phase average density and the free phase average density;

[0079] Step S400, using high-pressure mercury injection experiment and nuclear magnetic resonance experiment to determine the core-scale pore distribution law, and analyze it with the adsorption volume ratio to obtain the core-scale pore size distribution result;

[0080] Step S500, obtaining the adsorbed state and free state of hydrocarbon fluid in the core-scale pores according to the core-scale pore size distribution result.

[0081] Specifically, the density at each sampling point in any pore is collected to obtain density distribution data of the fluid in the pore, and the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore is calculated according to the density distribution data, so as to calculate the average density of the adsorption phase according to the average density of the single-layer adsorption phase, and the average density of the free phase is calculated according to the density distribution data, and the adsorption amount of the hydrocarbon fluid in the pore is calculated according to the adsorption amount per unit area, and the number of adsorption layers is obtained, and the thickness of the adsorption layer is calculated according to the number of adsorption layers, so as to calculate the free amount of the hydrocarbon fluid in the pore according to the adsorption amount per unit area and the thickness of the adsorption layer, and the adsorption mass ratio is calculated according to the adsorption amount and the free amount, so as to calculate the adsorption volume ratio according to the adsorption mass ratio, and the core-scale pore distribution law is determined by using high-pressure mercury injection experiment and nuclear magnetic resonance experiment, and analyzed with the adsorption volume ratio to obtain the full-size pore size distribution result of the core, and combined with the ratio of adsorption state and free state in the adsorption mass ratio, the adsorption state and free state of the hydrocarbon fluid in the full-size pores of the core can be obtained.

[0082] Specifically, by collecting the density of each sampling point in the pore, this embodiment can more accurately understand the distribution of hydrocarbon fluids in the pores, thereby obtaining more accurate pore structure information. By calculating the average density of the single-layer adsorption phase, the average density of the free phase, the adsorption amount and the free amount, the adsorption state and free state of the hydrocarbon fluid in the pore can be quantitatively analyzed, which provides a basis for analyzing the existence state of the fluid in the porous medium. Combined with the high-pressure mercury injection experiment and the nuclear magnetic resonance experiment, the core-scale pore distribution law can be determined, thereby obtaining the full-size pore size distribution result, which is helpful for evaluating the pore structure. By analyzing the adsorption mass ratio and the adsorption volume ratio, the adsorption state and free state of the hydrocarbon fluid in the pore can be identified, which provides a basis for predicting the flow and transmission of the fluid in the pore. Through the above analysis, the occurrence state of hydrocarbon fluids in the shale pore structure can be more accurately evaluated, which is of great significance for the development of hydrocarbon fluids in shale.

[0083] Specifically, the formula for calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data is:

[0084]

[0085] Among them, mali is the fluid adsorption mass of the i-th adsorption layer, V ali is the fluid adsorption volume of the i-th adsorption layer, ρ mass is the density of hydrocarbon fluid, in kg / m 3 , A m is the pore specific surface area, in nm 2 , L i is the i-th adsorption layer, where i=1, 2..., n, n>2, L ii is the adsorption layer adjacent to the i-th layer, ρ ali is the average density of the monolayer adsorption phase in the i-th adsorption layer.

[0086] Specifically, in practical applications, if the i-th adsorption layer is the adsorption layer set at the head and tail, the adsorption layer adjacent to it is directly used as L ii If the i-th adsorption layer is set in the middle, the adsorption layer in the opposite direction of the fluid extension direction is taken as L ii .

[0087] Specifically, this embodiment calculates the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore through density distribution data, which helps to predict the flow and transmission of fluid in the pores. During the data processing process, the formula can be used to quickly calculate the average density of the single-layer adsorption phase, reducing the complexity and time cost of data processing and improving research efficiency.

[0088] Specifically, the formula for calculating the average density of the adsorbed phase according to the average density of the monolayer adsorbed phase is:

[0089]

[0090] Among them, ρ a is the average density of the adsorption phase, the unit is kg / m3, n is the total number of adsorption layers, and i=1 is the first adsorption layer.

[0091] Specifically, this embodiment can evaluate the adsorption performance of hydrocarbon fluids in shale pores by calculating the average density of the adsorbed phase. Compared with traditional estimation or rough calculation methods, the formula calculation based on density distribution data can significantly reduce errors and improve the reliability and scientificity of the data.

[0092] Specifically, the calculation formula for the adsorption capacity per unit area is:

[0093]

[0094] Among them, C a is the adsorption amount per unit area.

[0095] Specifically, in this embodiment, the adsorption amount per unit area can be calculated to intuitively express the adsorption amount of the fluid in the pores, which is a key indicator for evaluating the adsorption capacity, helps to determine the adsorption of the fluid in the pores, and improves the accuracy and reliability of the prediction.

[0096] Specifically, the formula for calculating the adsorption amount of hydrocarbon fluid in the pores is:

[0097] Q a =A p ·(C a +C b )

[0098] Among them, Q a is the adsorption amount, C a and C b is the adsorption per unit area of ​​different pore walls, in mg / m 2 , A p is the internal surface area of ​​the pores.

[0099] Specifically, this embodiment can more accurately evaluate the adsorption amount of fluid in shale pores through scientific calculations, provide reliable data support for shale gas resource development, and help serve as an important indicator for studying pore structure and surface properties.

[0100] Specifically, the formula for calculating the average density of the free phase based on the density distribution data is:

[0101]

[0102] Among them, ρ f is the average density of the free phase, V f is the volume of the free phase, m f is the unit fluid free phase mass, V ali is the unit fluid free phase volume, ρ mass is the density of hydrocarbon fluid, in kg / m 3 , A m is the pore specific surface area, in nm 2 , L1 is the position where the free phase of hydrocarbon fluid begins to appear, and L2 is the position where the free phase of hydrocarbon fluid disappears.

[0103] Specifically, this embodiment uses density distribution data to accurately calculate the average density of the free phase, which helps to more accurately reflect the physical state and properties of the free phase and provides important data support for understanding and predicting fluids in pores.

[0104] Specifically, the formula for the adsorption layer thickness is:

[0105]

[0106] Where H is the thickness of the adsorption layer, t ai is the single layer adsorption thickness in nm, n is the number of adsorption layers, i=1, 2...n, n>2.

[0107] Specifically, the calculation formula for the free amount of hydrocarbon fluid in the pores is:

[0108] Q f =ρ f ·V f =ρ f ·A p (d m -2H)

[0109] Among them, Q f is the free amount, d m is the pore diameter in nm, and H is the adsorption layer thickness.

[0110] Specifically, this embodiment uses a computational method to quantitatively evaluate the free phase, and accurate quantification provides data support for the determination of the fluid storage state in the pores, which can reduce uncertainties in the development process and reduce technical risks.

[0111] Specifically, the calculation formula for calculating the adsorption mass ratio according to the adsorption amount and the free amount is:

[0112]

[0113] Among them, r am is the adsorption mass percentage.

[0114] Specifically, the calculation formula for calculating the adsorption volume ratio according to the adsorption mass ratio, the average density of the adsorbed phase and the average density of the free phase is:

[0115]

[0116] Among them, r av is the adsorption volume ratio, V a is the adsorption volume, V p is the volume of total hydrocarbon fluid.

[0117] Specifically, the process of obtaining the number of adsorption layers includes:

[0118] respectively obtaining the real-time hydrocarbon fluid density of each adsorption layer to be detected, obtaining the difference between the real-time hydrocarbon fluid density and the bulk fluid density, obtaining a real-time density difference, and determining the real-time density difference according to a standard density difference;

[0119] If the real-time hydrocarbon density difference is greater than the standard density difference, the adsorption layer to be detected is determined to be an adsorption layer;

[0120] If the real-time hydrocarbon density difference is less than or equal to the standard density difference, the adsorption layer to be detected is determined to be a non-adsorption layer;

[0121] When all the adsorption layers to be detected are judged, the number of adsorption layers is obtained to obtain the number of adsorption layers.

[0122] Specifically, the standard density difference is 2%.

[0123] Specifically, this embodiment can ensure the timeliness and accuracy of the data by obtaining the real-time fluid density of each adsorption layer to be detected, thereby more accurately reflecting the state of the adsorption layer. By setting the standard density difference as the basis for judgment, the boundary between the adsorption layer and the non-adsorption layer can be scientifically divided to reduce the error of judgment. Based on the real-time measurement and comparison of the density difference, it is possible to more accurately identify which layers are the adsorption layers.

[0124] See also Figure 2 As shown, the process of the high-pressure mercury injection experiment includes:

[0125] Step S410, filling the shale sample with mercury liquid and performing oil washing and drying treatment;

[0126] Step S420, placing the treated shale sample in a solid expansion agent filled with nitrogen, and moving it to a high-pressure mercury injection test instrument;

[0127] Step S430, performing low-pressure vacuum degassing in the high-pressure mercury injection experimental instrument, setting the experimental mercury injection pressure value, injecting mercury based on the lower limit of the pore size according to a preset program to obtain a capillary pressure curve, and the capillary pressure curve reflects the distribution curve of the pore size.

[0128] Specifically, this embodiment uses high-pressure mercury injection experiments to provide porosity measurements, that is, the ratio of pore volume to total volume. Based on the capillary pressure curve, the pore size distribution of shale samples can be accurately determined, which is crucial for understanding the pore structure.

[0129] Specifically, the process of the nuclear magnetic resonance experiment includes:

[0130] First, the free fluid in the pores of the shale sample is removed, and then the saturated hydrocarbon fluid is treated for testing. Then, the signal of the saturated hydrocarbon fluid is detected using nuclear magnetic resonance, and finally the pore volume of the shale sample is obtained.

[0131] Specifically, this embodiment removes free fluid and saturates hydrocarbon fluid through the nuclear magnetic resonance experiment to obtain the pore volume of the shale sample, which can more accurately analyze the pore structure.

[0132] Specifically, the process of obtaining core-scale pore size distribution results includes:

[0133] The peak values ​​of the distribution curve and the pore volume are compared to determine the distribution law of core-scale pores, and an analysis is performed based on the distribution law and the adsorption volume ratio to obtain the core-scale pore size distribution result.

[0134] Specifically, the peak values ​​of the pore size distribution curve and the pore volume are compared. By finding the peak point on the distribution curve, the pore volume percentage within different pore size ranges is determined, thereby revealing the distribution law of core-scale pores. Based on the results of the peak value comparison, the law of pore size distribution is analyzed, such as the concentrated area of ​​pore size and the change of pore volume with pore size. Considering the adsorption capacity of pores for fluids (such as hydrocarbon fluids, gas, and water), the adsorption volume percentage of pores with different pore sizes is analyzed. The core-scale pore size distribution results obtained by the analysis are output in the form of a graph. The output results are shown in Figure 1. Figure 3 .

[0135] Specifically, by comparing the distribution curve and the peak value of the pore volume, this embodiment can accurately identify the proportion and distribution of pores of different sizes in the core, which helps to gain a deeper understanding of the pore structure characteristics of the core. According to the distribution law of core-scale pores, the development value can be evaluated, thereby improving the recovery rate.

[0136] Specifically, the process of determining the adsorbed and free states of hydrocarbon fluids in the pores includes:

[0137] The existence state of hydrocarbon fluid in shale pores is determined based on the core-scale pore size distribution result and the adsorption mass ratio, the existence state is analyzed, and the adsorption state and free state of the hydrocarbon fluid in the pores are obtained according to the analysis result.

[0138] Specifically, by comparing the pore volume percentage and adsorption mass percentage within different pore size ranges, it is possible to analyze which pores mainly contain adsorbed hydrocarbon fluids and which pores mainly contain free hydrocarbon fluids. After completing the existence state analysis, the adsorbed state and free state of the hydrocarbon fluid in the pores can be determined based on the analysis results. The existence state results are shown in Figure 4 .

[0139] Specifically, this embodiment determines the adsorbed state and free state of the fluid through the core-scale pore size distribution results and the adsorption mass ratio, which helps to optimize the mining strategy, more accurately evaluate the reserves and development potential of shale resources, and reduce uncertainties in the development process.

[0140] So far, the technical solutions of the present invention have been described in conjunction with the preferred embodiments shown in the accompanying drawings. However, it is easy for those skilled in the art to understand that the protection scope of the present invention is obviously not limited to these specific embodiments. Without departing from the principle of the present invention, those skilled in the art can make equivalent changes or substitutions to the relevant technical features, and the technical solutions after these changes or substitutions will fall within the protection scope of the present invention.

[0141] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for quantitatively characterizing the fluid storage state in full-size pores of continental shale, characterized in that: include: Collecting the real-time density of the hydrocarbon fluid at each sampling point in any pore to obtain density distribution data of the hydrocarbon fluid in the pore, respectively calculating the average density of the single-layer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data, calculating the average density of the adsorption phase according to the average density of the single-layer adsorption phase, and calculating the average density of the free phase according to the density distribution data; Calculating the adsorption amount of the fluid in the pore according to the adsorption amount per unit area, obtaining the number of adsorption layers, and calculating the thickness of the adsorption layer according to the number of adsorption layers, so as to calculate the free amount of hydrocarbon fluid in the pore according to the adsorption amount per unit area and the thickness of the adsorption layer; Calculating the adsorption mass ratio according to the adsorbed amount and the free amount, and calculating the adsorption volume ratio according to the adsorbed mass ratio, the adsorbed phase average density and the free phase average density; Using high-pressure mercury injection experiments and nuclear magnetic resonance experiments, the core-scale pore distribution law is determined, and the adsorption volume ratio is analyzed to obtain the core-scale pore size distribution result; According to the core-scale pore size distribution result, the adsorbed state and free state of the hydrocarbon fluid in the core-scale pores are obtained.

2. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 1, characterized in that: The formula for calculating the average density of the monolayer adsorption phase corresponding to each adsorption layer in the pore according to the density distribution data is: Among them, m ali is the fluid adsorption mass of the i-th adsorption layer, V ali is the fluid adsorption volume of the i-th adsorption layer, ρ mass is the density of hydrocarbon fluid, in kg / m 3 , A m is the pore specific surface area, in nm 2 , L i is the i-th adsorption layer, where i=1, 2..., n, n>2, L ii is the adsorption layer adjacent to the i-th layer, ρ ali is the average density of the monolayer adsorption phase in the i-th adsorption layer.

3. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 2, characterized in that: The formula for calculating the average density of the adsorbed phase according to the average density of the monolayer adsorbed phase is: Among them, ρ a is the average density of the adsorption phase, the unit is kg / m3, n is the total number of adsorption layers, and i=1 is the first adsorption layer.

4. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 3, characterized in that: The calculation formula of the adsorption capacity per unit area is: Among them, C a is the adsorption amount per unit area.

5. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 4, characterized in that: The formula for calculating the adsorption amount of hydrocarbon fluid in the pores is: Q a =A p ·(C a +C b ); Among them, Q a is the adsorption amount, C a and C b is the adsorption per unit area at different positions in the pore wall, in mg / m 2 , A p is the internal surface area of ​​the pores.

6. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 5, characterized in that: The formula for calculating the average density of the free phase based on the density distribution data is: Among them, ρ f is the average density of the free phase, V f is the volume of the free phase, m f is the unit fluid free phase mass, V ali is the unit fluid free phase volume, L1 is the position where the hydrocarbon fluid free phase begins to appear, and L2 is the position where the hydrocarbon fluid free phase disappears.

7. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 6, characterized in that: The formula for the adsorption layer thickness is: Where H is the thickness of the adsorption layer, t ai is the monolayer adsorption thickness in nm.

8. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 7, characterized in that: The calculation formula for the free amount of hydrocarbon fluid in the pores is: Q f =ρ f ·V f =ρ f ·A p (d m -2H) Among them, Q f is the free amount, d m is the pore diameter in nm.

9. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 8, characterized in that: The calculation formula for calculating the adsorption mass ratio according to the adsorption amount and the free amount is: Among them, r am is the adsorption mass percentage.

10. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 9, characterized in that: The calculation formula for calculating the adsorption volume ratio according to the adsorption mass ratio, the adsorption phase average density and the free phase average density is: Among them, r av is the adsorption volume ratio, V a is the adsorption volume, V p is the volume of total hydrocarbon fluid.

11. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 10, characterized in that: The process of obtaining the number of adsorption layers includes: respectively obtaining the real-time hydrocarbon fluid density of each adsorption layer to be detected, obtaining the difference between the real-time hydrocarbon fluid density and the bulk fluid density, obtaining a real-time density difference, and determining the real-time density difference according to a standard density difference; If the real-time hydrocarbon density difference is greater than the standard density difference, the adsorption layer to be detected is determined to be an adsorption layer; If the real-time hydrocarbon density difference is less than or equal to the standard density difference, the adsorption layer to be detected is determined to be a non-adsorption layer; When all the adsorption layers to be detected are judged, the number of adsorption layers is obtained to obtain the number of adsorption layers.

12. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 11, characterized in that: The process of the high-pressure mercury injection experiment includes: The shale samples are filled with mercury liquid and subjected to oil washing and drying treatment; The treated shale sample is placed in a solid expansion agent filled with nitrogen and transferred to a high-pressure mercury injection experimental instrument; In the high-pressure mercury injection experimental instrument, low-pressure vacuum degassing treatment is performed, and the experimental mercury injection pressure value is set. Based on the lower limit value of the pore size, mercury is injected according to a preset program to obtain a capillary pressure curve, and the capillary pressure curve reflects the distribution curve of the pore size.

13. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 12, characterized in that: The process of the nuclear magnetic resonance experiment includes: First, the free fluid in the pores of the shale sample is removed, and then the hydrocarbon fluid is saturated for testing. Then, the signal of the saturated hydrocarbon fluid is detected using nuclear magnetic resonance, and finally the pore volume of the shale sample is obtained.

14. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 13, characterized in that: The process of obtaining core-scale pore size distribution results includes: The peak values ​​of the distribution curve and the pore volume are compared to determine the distribution law of core-scale pores, and an analysis is performed based on the distribution law and the adsorption volume ratio to obtain the core-scale pore size distribution result.

15. The method for quantitatively characterizing the fluid occurrence state in full-size pores of continental shale according to claim 14, characterized in that: The process of determining the adsorption state and free state of the hydrocarbon fluid in the pores according to the full-size pore size distribution result of the core and the existence state of the hydrocarbon fluid in the pores includes: The existence state of hydrocarbon fluid in shale pores is determined based on the core-scale pore size distribution result and the adsorption mass ratio, the existence state is analyzed, and the adsorption state and free state of the hydrocarbon fluid in the pores are obtained according to the analysis result.

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