Quantitative characterization method for fluid storage state in full-scale pores of continental shales

Abstract

The present invention relates to the occurrence state of shale fluids, and in particular to a method for quantitatively characterizing the occurrence state of fluids in full-scale pores of continental shale. The method comprises: collecting the real-time density of hydrocarbon fluids at sampling points in the pores to obtain density distribution data, and respectively calculating the average density of the single-layer adsorbed phase, the average density of the adsorbed phase, and the average density of the free phase in the pores; calculating the adsorption amount based on the adsorption amount per unit area, obtaining the number of adsorption layers, calculating the adsorption layer thickness based on the number of adsorption layers, and calculating the free amount based on the adsorption amount per unit area and the adsorption layer thickness; calculating the adsorption mass fraction based on the adsorption amount and the free amount, and calculating the adsorption volume fraction based on the adsorption mass fraction, the average density of the adsorbed phase, and the average density of the free phase; obtaining core-scale pore size distribution results using high-pressure mercury injection experiments and nuclear magnetic resonance experiments; thereby analyzing the adsorption and free states of the hydrocarbon fluids in the pores. This method allows for a more accurate assessment of the hydrocarbon fluid resource in shale.

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] Chinese patent application publication number CN117969365A discloses a method for quantitatively characterizing full-scale pores in tight reservoirs, comprising: S1: performing micrometer CT scanning on a full-diameter core sample of the 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 plug 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, the lower limit of the effective pore size of the reservoir; S5: The pore distribution intervals obtained in S1-S4 are integrated 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 existing technologies 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 objectives, the present invention provides a quantitative characterization of the fluid storage state in full-scale pores of continental shale, comprising:

[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, calculating the average density of the monolayer adsorbed phase corresponding to each adsorption layer in the pore based on the density distribution data, calculating the average density of the adsorbed phase based on the average density of the monolayer adsorbed phase, and calculating the average density of the free phase based on the density distribution data;

[0009] Calculating the adsorption amount of the fluid in the pores 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 pores 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 average density of the adsorbed phase and the average density of the free phase;

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

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

[0013] Furthermore, the formula for calculating the average density of the monolayer adsorption phase corresponding to each adsorption layer in the pores 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, in 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 adsorption layer thickness is:

[0029]

[0030] Where H is the thickness of the adsorption layer, t ai is the thickness of the single layer adsorption, 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 ratio.

[0037] Furthermore, the calculation formula for 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 to obtain a real-time density difference value, and determining the real-time density difference value according to a standard density difference value;

[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 determined, 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 test instrument;

[0048] A low-pressure vacuum degassing process is performed in the high-pressure mercury injection experimental instrument, 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, which reflects the pore size distribution curve.

[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 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.

[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 the core-scale pore size distribution result is obtained based on the distribution law and the adsorption volume ratio.

[0053] Furthermore, the process of determining the adsorbed state and free state of the hydrocarbon fluid in the pores based on the full-scale pore size distribution result of the core and the existence state of the hydrocarbon fluid in the pores includes:

[0054] The existence state of the hydrocarbon fluid in the 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 results.

[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 understood more accurately, thereby obtaining more accurate pore structure information; by calculating the average density of the single-layer adsorbed phase, the average density of the free phase, the adsorbed amount and the free amount, the adsorbed 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 adsorbed 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 helps to predict the flow and transmission of fluid in the pore. 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, accurately calculating the average density of the free phase 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, calculating the adsorption amount per unit area can intuitively express the adsorption amount of fluid in the pores, which is a key indicator for evaluating adsorption capacity. It helps to determine the adsorption situation 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 more accurately evaluated, providing reliable data support for shale gas resource development 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 error of judgment. 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 quantitative evaluation of the free phase through computational methods and accurate quantification provide data support for the determination of the fluid storage state in the pores, which can reduce uncertainty in the development process and lower technical risks.

[0063] In particular, high-pressure mercury injection experiments can 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.

[0064] In particular, by removing free fluid and saturating the 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 pattern 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 mining strategies, more accurately assess 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-scale pores of continental shale according to an embodiment of the present invention;

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

[0070] Figure 4 This is a diagram showing the occurrence state of fluids in full-scale pores of continental shale, which is 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 merely used to explain the present invention and are not intended 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 scope of protection 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 accompanying drawings. This is only 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] Furthermore, it should be noted that, in the description of the present invention, unless otherwise expressly specified or limited, the terms "mounted," "connected," and "connected" should be understood in a broad sense. For example, they may refer to fixed connections, detachable connections, or integral connections; they may refer to mechanical connections or electrical connections; they may refer to direct connections or indirect connections through an intermediate medium; and they may refer to internal communication between two components. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on the specific circumstances.

[0075] See also Figure 1 As shown, the present invention provides a method for quantitatively characterizing the fluid occurrence state in full-scale 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, calculating the average density of the monolayer adsorbed phase corresponding to each adsorption layer in the pore based on the density distribution data, calculating the average density of the adsorbed phase based on the average density of the monolayer adsorbed phase, and calculating the average density of the free phase based on 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, 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;

[0078] Step S300, calculating the adsorption mass ratio according to the adsorbed amount and the free amount, and 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;

[0079] Step S400, using high-pressure mercury injection experiments and nuclear magnetic resonance experiments to determine the core-scale pore distribution law, and analyzing 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, and the adsorption volume ratio is calculated according to the adsorption mass ratio. The core-scale pore distribution law is determined by using high-pressure mercury injection experiments and nuclear magnetic resonance experiments, and the adsorption volume ratio is analyzed to obtain the full-scale pore size distribution result of the core, and combined with the ratio of adsorbed state and free state in the adsorption mass ratio, the adsorption state and free state of the hydrocarbon fluid in the full-scale pores of the core can be obtained.

[0082] Specifically, this embodiment can more accurately understand the distribution of hydrocarbon fluids in the pores by collecting the density of each sampling point in the pores, thereby obtaining more accurate pore structure information. By calculating the average density of the single-layer adsorbed phase, the average density of the free phase, the adsorbed amount and the free amount, the adsorbed state and free state of the hydrocarbon fluid in the pores 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 results, which is helpful for evaluating the pore structure. By analyzing the adsorption mass ratio and the adsorption volume ratio, the adsorbed state and free state of the hydrocarbon fluid in the pores can be identified, which provides a basis for predicting the flow and transmission of the fluid in the pores. 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 monolayer 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 pore. 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.

[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, in 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 adsorption capacity, helps to determine the adsorption situation 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 capacity 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 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 thickness of the single layer adsorption, 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. Accurate quantification provides data support for determining the state of fluid in the pores, which can reduce uncertainty in the development process and lower technical risks.

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

[0112]

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

[0114] Specifically, the calculation formula for 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 to obtain a real-time density difference value, and determining the real-time density difference value according to a standard density difference value;

[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 determined, 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, 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.

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

[0125] Step S410, the shale sample is filled with mercury liquid and subjected to oil washing and drying treatment;

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

[0127] In step S430, low-pressure vacuum degassing is performed in the high-pressure mercury injection instrument, and a mercury injection pressure value for the experiment is set. Based on the lower limit of the pore size, mercury is injected according to a preset procedure to obtain a capillary pressure curve, which reflects the pore size distribution curve.

[0128] Specifically, this embodiment uses a high-pressure mercury injection experiment to provide a porosity measurement, that is, the ratio of pore volume to total volume. Based on the capillary pressure curve, the pore size distribution of the shale sample 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 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.

[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 the core-scale pore size distribution result is obtained based on the distribution law and the adsorption volume ratio.

[0134] Specifically, the peak values ​​of the pore size distribution curve and the pore volume are compared. By finding the peak points on the distribution curve, the pore volume proportions within different pore size ranges are determined, thereby revealing the distribution law of core-scale pores. Based on the results of the peak 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 proportions of pores with different pore sizes are 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 the hydrocarbon fluid in the 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 results.

[0138] Specifically, by comparing the pore volume percentage and adsorption mass percentage within different pore size ranges, we can 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 occurrence state results are shown in Figure 4 .

[0139] Specifically, this embodiment determines the adsorbed and free states 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] Thus far, the technical solutions of the present invention have been described in conjunction with the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art may make equivalent changes or substitutions to the relevant technical features, and the technical solutions after such changes or substitutions will fall within the scope of protection of the present invention.

[0141] The foregoing description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Those skilled in the art will readily appreciate that the present invention is susceptible to various modifications and variations. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention shall be included within the scope of protection of the present invention.

Claims

1. A method for quantitatively characterizing the fluid occurrence state in full-scale pores of continental shale, characterized by: 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, calculating the average density of the monolayer adsorbed phase corresponding to each adsorption layer in the pore based on the density distribution data, calculating the average density of the adsorbed phase based on the average density of the monolayer adsorbed phase, and calculating the average density of the free phase based on the density distribution data; Calculating the adsorption amount of the fluid in the pores 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 pores 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 average density of the adsorbed phase and the average density of the free phase; Using high-pressure mercury injection experiments and nuclear magnetic resonance experiments, the core-scale pore distribution law is determined, and the results are analyzed with the adsorption volume fraction to obtain the core-scale pore size distribution results; According to the core-scale pore size distribution result, the adsorbed state and free state of hydrocarbon fluid in the core-scale pores are obtained.

2. The method for quantitatively characterizing the fluid occurrence state in full-scale 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-scale 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, in 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-scale 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-scale 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-scale 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-scale 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 thickness of the monolayer adsorption, in nm.

8. The method for quantitatively characterizing the fluid occurrence state in full-scale 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-scale 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 ratio.

10. The method for quantitatively characterizing the fluid occurrence state in full-scale pores of continental shale according to claim 9, characterized in that: The calculation formula for 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-scale 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 to obtain a real-time density difference value, and determining the real-time density difference value according to a standard density difference value; 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 determined, 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-scale 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 test instrument; A low-pressure vacuum degassing process is performed in the high-pressure mercury injection experimental instrument, 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, which reflects the pore size distribution curve.

13. The method for quantitatively characterizing the fluid occurrence state in full-scale 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-scale 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 the core-scale pore size distribution result is obtained based on the distribution law and the adsorption volume ratio.

15. The method for quantitatively characterizing the fluid occurrence state in full-scale pores of continental shale according to claim 14, characterized in that: The process of determining the adsorbed state and free state of the hydrocarbon fluid in the pores based on the full-scale pore size distribution results of the core and the existence state of the hydrocarbon fluid in the pores includes: The existence state of the hydrocarbon fluid in the 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 results.

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