A method for identifying and tracing fluid states in complex nanopores of shale

Abstract

The present invention relates to a method for identifying and tracing the state of fluid in complex nanopores of shale. The method can accurately identify the state of fluid in complex nanopores of shale on a molecular scale and accurately trace the migration of fluid molecules in different states during the desorption process. In particular, the method can simultaneously achieve the following functions: accurately identify the state of fluid in complex nanopores; quantitatively analyze the mutual conversion of fluid molecules in different states; and achieve real-time tracing of any fluid state during the desorption process.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas development, and in particular relates to a method for identifying and tracing the state of fluid in complex nanopores of shale. Background Art

[0002] Shale reservoirs are highly heterogeneous, with diverse rock types and complex pore structures. Shale can be divided into organic and inorganic components. Kerogen is the main component of organic matter, accounting for 80% to 90% of the total organic matter; inorganic matter mainly includes detrital minerals, clay minerals and carbonate minerals; kerogen has an amorphous macromolecular structure, and the matrix contains abundant micro-nano pores, with diverse and complex pore types; micro-nano pores of different sizes, shapes and connectivity are randomly distributed in inorganic minerals; in actual shale reservoirs, organic and inorganic matter are usually mixed, forming a large number of organic-inorganic composite pores between the two;

[0003] There are various types of fluids in the pores of shale reservoirs. Different fluids have different occurrence characteristics and interfere with each other, resulting in complex occurrences. In addition, the occurrence states of fluids in complex pores of shale reservoirs are diverse. Fluids can form adsorption phases on the surface of kerogen and inorganic minerals, dissolved phases inside the kerogen matrix, and free phases in the middle of large pores. The occurrence characteristics of fluids in different states are different, and different states are difficult to distinguish. Clarifying the occurrence characteristics of fluids in shale reservoirs and accurately identifying the state of fluids are of great significance to shale gas reserve assessment and evaluation of shale reservoir gas storage capacity.

[0004] In the depletion development of shale gas reservoirs, CO2 injection enhanced production, and hydrogen storage and recycling, the occurrence characteristics and production rules of fluids in shale reservoirs are crucial; when shale reservoir fluids are produced and utilized, different fluid states have different production rules, and there are differences in the difficulty of production. In addition, different fluid states will undergo mutual conversion, and it is very difficult to distinguish and quantify the production degree of different fluid states; clarifying the production degree and mutual conversion characteristics of different fluid states is the basis for a deep understanding of the storage, flow and recovery mechanism of shale reservoir fluids;

[0005] Although closely related to the fluid utilization characteristics of shale reservoirs, there is currently a lack of research on fluid state identification, quantification and tracing of the utilization of different fluid states; conventional physical simulation experiments and numerical simulation methods can only calculate the total fluid intake and total production in shale and shale reservoirs, but cannot identify different fluid states and distinguish and quantify their utilization laws, nor can they trace different fluid states during the desorption process; the present invention aims to provide a set of molecular simulation methods for identifying and tracing fluid states in complex nanopores of shale, to maximize the distinction between the occurrence states of fluids in shale, to accurately trace different states of fluids during the production process, and then to restore the fluid occurrence characteristics and fluid utilization laws in complex nanopores of shale at the molecular scale. Summary of the invention

[0006] The purpose of the present invention is to provide a method for identifying and tracing the fluid state in complex nanopores of shale, so as to solve the problems existing in the background technology.

[0007] In order to achieve the above technical objectives, the technical solution adopted by the present invention is as follows:

[0008] A method for identifying and tracing the fluid state in complex nanopores of shale, specifically comprising the following steps:

[0009] S1: Construction of complex nanopore model of shale;

[0010] S2: fluid state recovery;

[0011] S3: Fluid state identification and labeling;

[0012] S4: desorption process simulation;

[0013] S5: Tracing of different fluid states.

[0014] Preferably, in step S1, the shale inorganic-kerogen composite slit nanopore model is composed of inorganic matter and kerogen, in which the fluid is subjected to the coupling effect of organic matter and inorganic matter, and inorganic micropores of small, medium and large sizes are obtained by cutting blocks of different sizes from the inorganic sheet. In addition to the intermolecular pores in the kerogen, virtual particles are added to expand the kerogen topological structure to obtain artificial organic micropores, and the size of the virtual particles is less than In order to prevent the existence of free phase fluid, the inorganic sheets and kerogen sheets are tightly fitted to form composite medium sheets, and then the composite medium sheets are stacked to form inorganic slit pores, thereby obtaining a complex nanopore model of shale containing kerogen intermolecular pores, kerogen artificial micropores, inorganic micropores and inorganic slit pores.

[0015] Preferably, in step S1, based on the shale nanopore model, two isolation layers are superimposed to expand a matching vacuum layer, the vacuum layer represents the fractures in the shale reservoir, and the external pressure of the composite pores can be controlled. The isolation layer is an inert gas layer because the inert gas layer can both act as a barrier and not interact with the fluid molecules.

[0016] Preferably, in step S2, based on the shale complex nanopore model constructed in step S1, according to the original temperature and pressure conditions of the reservoir, the reservoir pressure is converted into fugacity as an input parameter in combination with the state equation, and the GCMC method is used to carry out fluid molecule loading. Specifically, the fluid molecules are restricted to be loaded only in the shale composite medium area. After the GCMC simulation, the MD simulation is used to carry out the diffusion of the fluid in the composite medium area to achieve fluid distribution balance.

[0017] Preferably, in step S3, the fluid state is identified: the thickness of the fluid adsorption layer is determined based on the fluid molecular distribution configuration obtained in step S2; then the complex nanopore model of shale is combined to carry out fine zoning, specifically, the fluid in the kerogen matrix pore area is defined as the dissolution zone, the area of ​​the larger pore that is away from the pore wall by the thickness of one adsorption layer is defined as the free zone, and the area within the thickness of one adsorption layer near the pore wall is defined as the adsorption zone; then the fluid state is identified in combination with the position of the fluid molecules, specifically, the fluid located in the dissolution zone is identified as the dissolved phase, the fluid located in the free zone is identified as the free phase, and the fluid located in the adsorption zone is identified as the adsorption phase; then the number of molecules of the fluid state in different configurations is calculated and the ensemble average is taken to obtain the occurrence of fluids in different states in the shale pores.

[0018] Preferably, in step S3, fluid state marking: select the lowest energy configuration obtained in step S2 for fluid state identification, and mark the fluid molecules in the fluid free phase, adsorbed phase and dissolved phase as a, b, c respectively by modifying the molecular type numbers of the fluid molecules and record the contents of different states.

[0019] Preferably, in step S4, based on the shale complex nanopore model after marking the fluid molecules in step S3, the fluid pressure in the fracture vacuum layer is first reduced by the GCMC algorithm, and then the inert gas layer blocking the shale composite medium and the fracture vacuum layer is deleted to connect the shale composite medium area and the fracture vacuum layer area, and then the MD method is used to simulate the decompression desorption process of the fluid in the shale composite medium area under a given fracture vacuum layer pressure.

[0020] Preferably, in step S5, for the model system after the desorption simulation equilibrium in step S4, based on the fluid trajectory file after the desorption simulation equilibrium obtained by MD simulation, combined with the fluid state identification method in step S3, the occurrence amount of fluids in different occurrence states in the shale composite medium area is determined, and it is compared with the occurrence amount of fluids in various states before desorption to clarify the degree of recovery of fluids in different states.

[0021] Preferably, in step S5, based on the fluid trajectory file after desorption simulation equilibrium obtained by MD simulation, the number of three types of fluid molecules a, b, and c in the free phase, adsorbed phase, and dissolved phase of the fluid under different configurations in the shale composite medium region is counted and the ensemble average is calculated, which is compared with the quantified fluid state reserves before desorption, thereby quantifying the mutual conversion amount between different states of the fluid.

[0022] Preferably, in step S5, based on the trajectory file obtained by MD during the desorption simulation process, target fluid molecules are selected in the fluid free phase, adsorption phase and dissolved phase respectively, and by recording the position changes of the target fluid molecules during the desorption process, the migration paths of the molecules in different states of the fluid are determined and traced in real time.

[0023] The present invention provides a molecular simulation method for identifying and tracing the state of fluid in complex nanopores of shale. A complex nanopore fluid desorption simulation system of shale is constructed by using the method. The microscopic system not only has a composite structure formed by shale kerogen and inorganic minerals, but also has pores between kerogen molecules, organic micropores, inorganic micropores of different sizes and inorganic slit pores, which restores the occurrence of fluids in different states in the complex pores of shale; the fluid state is accurately identified by combining fine zoning and fluid distribution position, and the fluids in different states are accurately traced during the desorption process by a labeling and tracing method, the diffusion characteristics of fluids in different states are studied, the mutual conversion of fluids in different states is considered, and the diffusion behavior of fluids in different states during the production of shale reservoir fluids is reproduced; in particular, the method can simultaneously realize the following functions: 1. Accurately identify the state of fluids in complex nanopores; 2. Quantitatively analyze the mutual conversion of fluid molecules in different states, and accurately calculate the recovery rate of fluids in different states; 3. Realize real-time tracing of any fluid state during the desorption process. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] The present invention is further illustrated by means of the non-limiting examples given in the accompanying drawings.

[0025] Figure 1 The research process of the method for identifying and tracing the fluid state in the complex nanopores of shale of the present invention;

[0026] Figure 2 is a table of kerogen structure relaxation steps of the present invention;

[0027] Figure 3 The shale complex nanopore model of the present invention;

[0028] Figure 4 The shale complex nanopore desorption model of the present invention;

[0029] Figure 5 The fluid state identification and labeling diagram in the complex nanopores of shale of the present invention;

[0030] Figure 6 It is a real-time diffusion trajectory tracer diagram of hydrogen dissolved phase molecules of the present invention;

[0031] Figure 7 is the number of hydrogen molecules in different states that are converted to each other in the present invention;

[0032] Figure 8 The figure is a comparison of the recovery rates of hydrogen in different states according to the present invention. DETAILED DESCRIPTION

[0033] In order to enable those skilled in the art to better understand the present invention, the technical solution of the present invention is further described below in conjunction with the accompanying drawings and embodiments.

[0034] Definitions of abbreviations and key terms in the present invention: Fluid state: The fluid state in shale is divided into free phase, adsorbed phase and dissolved phase; the fluid molecules in the middle of the larger pores have the same density as that in the bulk phase, and the influence of the pore wall can be ignored, which is called the free phase; the fluid molecules on the pore wall surface interact strongly with the pore wall and are enriched near the pore wall, which is called the adsorbed phase; the fluid molecules in the matrix nanopores inside the organic matter are dissolved or absorbed, so that the fluid molecules and the organic matter form a relatively uniform mixed phase in molecular state, which is called the dissolved phase;

[0035] A method for identifying and tracing the fluid state in complex nanopores of shale, the flow chart of which is as follows Figure 1 As shown, the specific steps include:

[0036] Step S1, building a complex nanopore model of shale, constructing an initial cube simulation box, the dimensions of the box in the x, y, and z directions are Then put two The virtual particles are fixed. After the simulation box is built, 10 IID (C 175 H 102 O 9 N 4 S 2 ) type kerogen structural unit, using Figure 2 The kerogen structure relaxation was carried out according to the steps in the previous section to obtain a balanced kerogen matrix molecular model. A 6a×6b×6c supercell structure was established along the x, y, and z directions, and a matrix block was cut out in the center of the matrix model. The organic layer is then removed to obtain larger artificial organic micropores. Illite unit cells are selected and firstly cut out a thin layer with a thickness of , and then build a 4a×4b×1c supercell structure along the x and y directions to obtain a size of The illite medium sheet is then cut to obtain the illite medium sheets with widths of The illite inorganic micropores are formed by closely fitting the illite lamellae and the kerogen lamellae to form a composite medium lamellae, and then the composite medium lamellae are stacked to form inorganic slit pores. Thus, an illite-kerogen composite shale nanopore model containing kerogen intermolecular pores, artificial organic micropores, inorganic micropores and inorganic slit pores is obtained. Its structure is shown in the figure. Figure 3 As shown, the aperture constructed by stacking composite dielectric sheets is The illite-kerogen composite slit nanopore model is closely superimposed on the proximal isolation layer, and the proximal isolation layer is separated from the distal isolation layer by a large gap. The vacuum layer is expanded to build a vacuum layer, which represents the fractures in the reservoir, and can realize the control of the external pressure of the composite pores. The isolation layer is the He layer, thus obtaining the following Figure 4 The depleted gas reservoir hydrogen storage and hydrogen recovery simulation device shown.

[0037] Step S2, based on the shale complex nanopore model constructed in step S1, using the GCMC method, according to the typical shale reservoir temperature (65°C) and pressure conditions (30MPa), the hydrogen pressure at the corresponding temperature is converted into fugacity as an input parameter through the Peng-Robinson state equation. Specifically, the hydrogen molecules are restricted to be adsorbed only in the shale composite medium area, and the GCMC method is used to realize the insertion, deletion and movement of hydrogen, to achieve accurate determination of the gas chemical potential, and to obtain a large number of adsorption configurations; in the external volume control area, the He layer prevents the hydrogen molecules from diffusing into the large cracks. For the entire simulation system, the MD method is used to realize the diffusion and migration of gas molecules, and the gas mass diffusion transfer is considered.

[0038] Step S3, fluid state identification: based on the different hydrogen adsorption configurations obtained in step S2, the average thickness of the hydrogen adsorption layer is obtained. Combined with the fine partitioning and hydrogen distribution position, the hydrogen in the kerogen matrix pore area is defined as the dissolved phase and the area is defined as the dissolved area. For hydrogen in other pores of the model, the area with a hydrogen adsorption layer thickness away from the pore wall in the illite micropores and illite slit pores is defined as the free area, and the hydrogen therein is defined as the free phase. The area within the thickness of the hydrogen adsorption layer near the pore wall is defined as the adsorption area, and the hydrogen therein is defined as the adsorption phase. Based on the adsorption configuration after hydrogen state identification, the number of hydrogen molecules in different states in each adsorption configuration is obtained and the average value is obtained, thereby obtaining the amount of hydrogen in different states in the shale pores; Fluid state marking: Select the lowest energy configuration obtained in step S2 for fluid state identification, mark the hydrogen molecules in the fluid free phase, adsorption phase and dissolved phase as 1, 2, 3 respectively, and record their molecular types and quantities. The results after hydrogen state identification and marking in complex nanopores of shale are as follows: Figure 5 As shown, it can be seen that the width is and The illite micropores have narrow pore spaces, and the hydrogen therein is in the adsorbed phase.

[0039] Step S4, based on the hydrogen adsorption model in complex nanopores of shale after marking the fluid molecules in step S3, the GCMC algorithm is used to reduce the hydrogen pressure in the fractures so that the system pressure after decompression and desorption is equal to the 10MPa pressure of the actual shale reservoir after decompression and desorption, and the He atoms at the connection between the proximal He isolation layer and the illite slit pores are deleted to connect the slit pore area and the fracture area. Then, the MD method is used to simulate the decompression and desorption process of the system under a pressure difference of 20MPa.

[0040] Step S5, based on the desorption simulation in step S4, the migration paths of the hydrogen molecules numbered 1, 2, and 3 during the desorption process are recorded to trace them in real time, wherein the real-time diffusion trajectory tracer of the dissolved phase hydrogen molecule numbered 3 is shown in FIG. Figure 6 As shown, it can be seen that the dissolved hydrogen first diffuses from the kerogen matrix pores through the illite micropores to the narrow pores, and then makes irregular movements to gradually diffuse to the large cracks, and the conversion between the free phase and the adsorption phase occurs many times on the way until it diffuses to the large cracks; the number of three types of hydrogen molecules numbered 1, 2, and 3 in the free zone, adsorption zone, and dissolution zone of each configuration after the desorption simulation is stabilized are counted and the average values ​​are calculated respectively, and the number of hydrogen molecules numbered 2 and 3 in the free zone is the conversion number of hydrogen adsorption phase and dissolution phase to the free phase, and the calculation method of phase conversion between adsorption zone and dissolution zone is the same; Figure 7 is the exchange amount of hydrogen in different states during the desorption process. It can be seen that there is mutual conversion between hydrogen in different states, among which the conversion amount from dissolved phase and adsorbed phase to free phase is relatively large. The number of hydrogen molecules numbered 1 in the free zone before and after desorption is subtracted to obtain the free phase hydrogen desorption rate considering interphase exchange. The calculation method of the desorption rate of hydrogen adsorbed phase and dissolved phase considering interphase exchange is the same as that of the free phase. The number of three hydrogen molecules numbered 1, 2, and 3 in different regions is added to obtain the hydrogen content of the corresponding state after analysis. The number of hydrogen molecules in the same state before and after desorption is subtracted to obtain the hydrogen desorption amount in different states without considering the mutual conversion between phases. Figure 8 The hydrogen recovery rate in different states of whether phase conversion is considered or not. It can be seen that when phase conversion is not considered, the recovery rate of the adsorption phase is the highest; when phase conversion is considered, the recovery rate of the free phase is the highest; in addition, whether phase conversion is considered or not has little effect on the recovery rate of the dissolved phase.

[0041] The above embodiments are merely illustrative of the principles and effects of the present invention, and are not intended to limit the present invention. Anyone familiar with the technology may modify or change the above embodiments without violating the spirit and scope of the present invention. Therefore, all equivalent modifications or changes made by those with ordinary knowledge in the technical field without departing from the spirit and technical ideas disclosed by the present invention should still be covered by the claims of the present invention.

Claims

1. A method for identifying and tracing the fluid state in complex nanopores of shale, characterized by: The steps include: S1: Construction of complex nanopore model of shale; The complex nanopore model of shale is composed of inorganic matter and kerogen, in which the fluid is coupled by organic matter and inorganic matter. By cutting blocks of different sizes from the inorganic sheet, small, medium and large inorganic micropores are obtained. In addition to the intermolecular pores in the kerogen, virtual particles are added to expand the kerogen topological structure to obtain artificial organic micropores. The size of the virtual particles is less than 20Å to prevent the existence of free phase fluid. The inorganic sheet and the kerogen sheet are closely fitted to form a composite medium sheet, and then the composite medium sheets are superimposed to form inorganic slit pores. Thus, a complex nanopore model of shale containing kerogen intermolecular pores, kerogen artificial micropores, inorganic micropores and inorganic slit pores is obtained. Based on the complex nanopore model of shale, two isolation layers are superimposed to expand the matching vacuum layer. The vacuum layer represents the fractures in the shale reservoir to achieve the control of the external pressure of the composite pores. The isolation layer uses an inert gas layer. S2: fluid state recovery; Based on the shale complex nanopore model constructed in step S1, according to the original temperature and pressure conditions of the reservoir, the reservoir pressure is converted into fugacity as an input parameter in combination with the state equation, and the GCMC method is used to load fluid molecules, restricting the fluid molecules to be loaded only in the shale composite medium area. After the GCMC simulation, the MD simulation is used to carry out the diffusion of the fluid in the composite medium area to achieve fluid distribution balance; S3: Fluid state identification and labeling; Fluid state identification: Determine the thickness of the fluid adsorption layer based on the fluid molecular distribution configuration obtained in step S2; then conduct fine zoning in combination with the complex nanopore model of shale, define the fluid in the pore area of ​​kerogen matrix as the dissolution zone, define the area of ​​the larger pores that is one adsorption layer thickness away from the pore wall as the free zone, and define the area within one adsorption layer thickness near the pore wall as the adsorption zone; then identify the fluid state in combination with the position of the fluid molecules, identify the fluid in the dissolution zone as the dissolved phase, the fluid in the free zone as the free phase, and the fluid in the adsorption zone as the adsorption phase; then calculate the number of molecules in the fluid state in different configurations and take the ensemble average to obtain the occurrence of fluids in different states in the shale pores; S4: desorption process simulation; S5: Tracing of different fluid states.

2. The method for identifying and tracing fluid states in complex nanopores of shale according to claim 1, characterized in that: In step S3, fluid state marking: select the lowest energy configuration obtained in step S2 for fluid state identification, and mark the fluid molecules in the free phase, adsorbed phase and dissolved phase as a, b, c respectively by modifying the molecular type number of the fluid molecules, and record the different state contents.

3. The method for identifying and tracing fluid state in complex nanopores of shale according to claim 2, characterized in that: In step S4, based on the shale complex nanopore model after marking the fluid molecules in step S3, the GCMC algorithm is first used to reduce the fluid pressure in the fracture vacuum layer, and then the inert gas layer blocking the shale composite medium and the fracture vacuum layer is deleted to connect the shale composite medium area and the fracture vacuum layer area. Then, the MD method is used to simulate the decompression desorption process of the fluid in the shale composite medium area under a given fracture vacuum layer pressure.

4. The method for identifying and tracing fluid state in complex nanopores of shale according to claim 3, characterized in that: In step S5, for the model system after the desorption simulation equilibrium in step S4, based on the fluid trajectory file after the desorption simulation equilibrium obtained by MD simulation, combined with the fluid state identification method in step S3, the occurrence amount of fluids in different occurrence states in the shale composite medium area is determined, and it is compared with the occurrence amount of fluids in various states before desorption to clarify the recovery degree of fluids in different states.

5. The method for identifying and tracing fluid state in complex nanopores of shale according to claim 4, characterized in that: In step S5, based on the fluid trajectory file after the desorption simulation equilibrium obtained by MD simulation, the number of three types of fluid molecules a, b, and c in the free phase, adsorption phase, and dissolved phase of the fluid under different configurations in the shale composite medium area is counted and the ensemble average is calculated, which is compared with the quantified fluid state reserves before desorption, thereby quantifying the mutual conversion amount between different fluid states.

6. The method for identifying and tracing fluid states in complex nanopores of shale according to claim 5, characterized in that: In step S5, based on the fluid trajectory file obtained by MD during the desorption simulation, target fluid molecules are selected in the fluid free phase, adsorption phase, and dissolved phase respectively. By recording the position changes of the target fluid molecules during the desorption process, the migration paths of the molecules in different states of the fluid are determined and traced in real time.

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