Upscaling modeling method and system for gas-water relative permeability in hydrate-containing sediments

Abstract

The present invention discloses a method and system for scaling up the gas-water relative permeability modeling of hydrate-containing sediments, which relates to the field of natural gas hydrate resource exploitation. The method for scaling up the gas-water relative permeability modeling of hydrate-containing sediments mainly comprises the following steps: obtaining the characterization areas and porosities of fine pore areas, medium pore areas and coarse pore areas according to the three-dimensional digital core image; obtaining the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area by using pore network image processing analysis tools and porous media pore network models; constructing an equivalent hydrate-containing sediment core model, carrying out core-scale single-phase fluid flow simulation and gas-water two-phase flow simulation, and obtaining the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model. The implementation of the method and system provided by the present invention can achieve effective prediction of the core-scale gas-water relative permeability of hydrate-containing sediments.

Description

Technical Field

[0001] The present invention relates to the field of natural gas hydrate resource exploitation, and more specifically to a method and system for upscaling modeling of gas-water relative permeability of hydrate-containing sediments. Background Art

[0002] Natural gas hydrate is an efficient and clean energy with high energy density, wide distribution and huge reserves. It is mainly distributed in deep-sea sediments and terrestrial permafrost. The exploitation and utilization of natural gas hydrates has an important impact on solving global climate and environmental problems, and is of great significance to adjusting the energy structure and alleviating energy shortages. However, the commercial development of natural gas hydrates faces huge challenges. In addition to environmental problems such as carbon leakage and marine geological disasters that may be caused by hydrate decomposition, the production efficiency of natural gas hydrates is also one of the most important factors limiting exploitation. The gas-water relative permeability of hydrate-containing sediments is the main controlling factor affecting the multiphase seepage of natural gas hydrate reservoirs and directly determines the development efficiency of hydrates. Therefore, the gas-water relative permeability of hydrate-containing sediments plays an important role in the exploitation of natural gas hydrates and the assessment of large-scale seafloor instability and global climate change caused by hydrate dissociation.

[0003] The difficulty, time-consuming and high cost of core sampling in actual operations, as well as the limitations of logging data, restrict the testing of gas-water relative permeability of hydrate-bearing sediments in the field. Indoor experiments (steady-state method and non-steady-state method) are used by scholars as an alternative method to determine the gas-water relative permeability of hydrate-bearing sediments. However, the indoor experimental method faces the bottleneck of accurately controlling the test pressure, temperature and hydrate saturation in the sediment. At present, the indoor experimental method cannot evaluate whether hydrate phase change (hydrate decomposition or secondary formation) occurs during the test process and the impact of hydrate phase change on the test results of gas-water relative permeability. Due to the lack of recognized experimental methods and the lack of national standards, there are great differences between the gas-water relative permeabilities tested in indoor experiments. Therefore, predicting the gas-water relative permeability of hydrate-bearing sediments based on the pore structure of hydrate-bearing sediments and microscale seepage models (such as pore network model, lattice Boltzmann, finite element method and finite volume method) is a current research hotspot. However, the hydrate occurrence forms of the South China Sea hydrate reservoirs in my country are complex and diverse, and the reservoir geological characteristics are significantly heterogeneous in space. The microscale flow process and prediction results are quite different from the core scale flow process and prediction results. How to establish a bridge relationship between the microscale prediction results and the core scale gas-water relative permeability and realize the upscaling modeling of the pore scale to the core scale gas-water relative permeability is the bottleneck facing the multiphase seepage of hydrate reservoirs. Summary of the invention

[0004] The object of the present invention is to provide a method and system for upscaling modeling of gas-water relative permeability of hydrate-containing sediments, which can achieve effective prediction of core-scale gas-water relative permeability of hydrate-containing sediments.

[0005] The invention provides a method for upscaling modeling of gas-water relative permeability of hydrate-containing sediments, comprising the following steps: S1: obtaining a CT image of a hydrate-containing sediment core, and obtaining a three-dimensional digital core image by using a non-local mean filtering algorithm; S2: obtaining, according to the three-dimensional digital core image, the characterization areas of fine pore areas, medium pore areas and coarse pore areas and their porosities; S3: obtaining, according to the characterization areas of the fine pore areas, medium pore areas and coarse pore areas, the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area by using a pore network image processing analysis tool and a porous medium pore network model; S4: obtaining an equivalent hydrate-containing sediment core model according to the characterization areas of the fine pore areas, medium pore areas and coarse pore areas and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area; S5: carrying out core-scale single-phase fluid flow simulation and gas-water two-phase flow simulation according to the equivalent hydrate-containing sediment core model, and obtaining the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model.

[0006] Furthermore, step S2 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S21: cropping the three-dimensional digital core image to obtain the approximate area of ​​the core; S22: using a histogram-based threshold algorithm to divide the approximate area to obtain the characterization area; S23: based on the characterization area, obtaining the porosity of each characterization area; S24: based on the porosity of each characterization area and a preset porosity interval, obtaining the characterization area of ​​fine pore area, medium pore area and coarse pore area.

[0007] Further, step S3 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S31: according to the characterization areas of fine pore area, mesopore area and coarse pore area, using pore network image processing and analysis tools, obtain pore structure information of the characterization areas of fine pore area, mesopore area and coarse pore area; S32: according to the pore structure information of the characterization areas of fine pore area, mesopore area and coarse pore area, using porous media pore network model, carry out single-phase water pore network simulation and gas-water two-phase flow simulation respectively, and obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, such as formula:

[0008]

[0009]

[0010]

[0011]

[0012] Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the gas-water relative permeability, k α is the effective permeability of gas or water in gas-water two-phase flow, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, w represents water, P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

[0013] Furthermore, step S4 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S41: According to the characterization areas of fine pore area, medium pore area and coarse pore area, the spatial position relationship of the three areas in the digital core image is utilized, and the corresponding characterization unit volumes are used to regroup to obtain the characterization unit volumes of the fine pore area, medium pore area and coarse pore area; S42: According to the characterization unit volumes of the fine pore area, medium pore area and coarse pore area, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area are mapped to the corresponding characterization unit volumes of the fine pore area, medium pore area and coarse pore area to obtain an equivalent hydrate-containing sediment core model.

[0014] Furthermore, step S5 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S51: According to the equivalent hydrate-containing sediment core model, a core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, such as the formula:

[0015]

[0016]

[0017]

[0018] Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term of water, t is time, x is the distance along the flow direction, k is the absolute permeability at the pore scale, μ w is the viscosity of water, Pw is the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate sediment core model, q is the flow rate at the outlet of the equivalent hydrate sediment core at the time of obtaining stability, L is the length of the equivalent core along the flow direction, and A is the cross-sectional area; S52: According to the equivalent hydrate sediment core model, a gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate sediment core model, as shown in the formula:

[0019]

[0020]

[0021]

[0022]

[0023]

[0024]

[0025]

[0026] Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α represents the flow rate of water or gas at the outlet of the equivalent hydrate-containing sediment core at the time of obtaining stability, α represents gas or water, g represents gas, w represents water, and k rα is the relative permeability of gas and water at the pore scale, p α is the gas phase or water phase pressure, K rw is the relative permeability of water phase in the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas outlet flow rate at the stable moment.

[0027] The present invention also provides a system, including the following modules: a three-dimensional digital core image module, configured to obtain a CT image of a hydrate-containing sediment core, and obtain a three-dimensional digital core image using a non-local mean filtering algorithm; a characterization region division module, configured to obtain characterization regions and porosities of fine pore regions, medium pore regions, and coarse pore regions according to the three-dimensional digital core image; a physical property parameter calculation module, configured to obtain the characterization regions of the fine pore regions, medium pore regions, and coarse pore regions according to the characterization regions using a pore network image processing analysis tool and a porous medium pore network model; The equivalent hydrate sediment core model generation module is configured as follows: according to the characterization areas of the fine pore area, the medium pore area and the coarse pore area and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, the equivalent hydrate sediment core model is obtained; the flow simulation module: according to the equivalent hydrate sediment core model, the core-scale single-phase fluid flow simulation and the gas-water two-phase flow simulation are carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate sediment core model.

[0028] Furthermore, the characterization area division module of the above-mentioned system is configured as follows: cropping the three-dimensional digital core image to obtain the approximate area of ​​the core; using a histogram-based threshold algorithm to divide the approximate area to obtain the characterization area; according to the characterization area, obtaining the porosity of each characterization area; according to the porosity of each characterization area and a preset porosity interval, obtaining the characterization areas of the fine pore area, the medium pore area and the coarse pore area.

[0029] Furthermore, the physical property parameter calculation module of the above-mentioned system has the following configurations: according to the characterization areas of the fine pore area, the mesopore area and the coarse pore area, the pore network image processing and analysis tool is used to obtain the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area; according to the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area, the porous medium pore network model is used to respectively carry out single-phase water pore network simulation and gas-water two-phase flow simulation to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, as shown in the formula:

[0030]

[0031]

[0032]

[0033]

[0034] Where k is the absolute permeability, q is the flow rate, μ wis the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the gas-water relative permeability, k α k α is the effective permeability of gas or water in gas-water two-phase flow, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, w represents water, P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

[0035] Furthermore, the equivalent hydrate-containing sediment core model generation module of the above-mentioned system has the following configurations: according to the representation areas of the fine pore area, the medium pore area and the coarse pore area, the spatial position relationship of the three areas in the digital core image is utilized, and the representation units of the fine pore area, the medium pore area and the coarse pore area are obtained by using the corresponding representation unit volumes to regroup; according to the representation unit volumes of the fine pore area, the medium pore area and the coarse pore area, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each representation area are mapped to the corresponding representation unit volumes of the fine pore area, the medium pore area and the coarse pore area to obtain the equivalent hydrate-containing sediment core model.

[0036] Furthermore, the flow simulation module of the above system is configured as follows: according to the equivalent hydrate-containing sediment core model, a core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, such as the formula:

[0037]

[0038]

[0039]

[0040] Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term, t is time, x is the distance along the flow direction, k is the pore-scale absolute permeability, μ w is the viscosity of water, P wis the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate sediment core model, q is the flow rate at the outlet of the equivalent hydrate sediment core model at the time of obtaining stability, L is the length of the core in the flow direction, and A is the cross-sectional area. According to the equivalent hydrate sediment core model, the gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate sediment core model, as shown in the formula:

[0041]

[0042]

[0043]

[0044]

[0045]

[0046]

[0047]

[0048] Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α represents the flow rate of water or gas at the outlet of the equivalent hydrate-containing sediment core at the time of obtaining stability, α represents gas or water, g represents gas, w represents water, and k rα is the relative permeability of gas and water at the pore scale, p α is the gas phase or water phase pressure, K rw is the water relative permeability of the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas flow rate.

[0049] The implementation of the method and system for upscaling modeling of gas-water relative permeability of hydrate-containing sediments provided by the present invention has the following beneficial effects:

[0050] The invention is based on CT scan images of porous sediments. It divides the heterogeneous hydrate-containing digital core images into multiple regions according to the pore size distribution or porosity size of the pore structure, and uses the pore network model to calculate the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each region; based on the spatial distribution of each region in the digital core, the equivalent hydrate-containing sediment core model is reconstructed and the calculation results of the pore network model are mapped to the corresponding positions; single-phase (water) and gas-water two-phase flow simulations are performed on the equivalent hydrate core model, the seepage equation is solved using the finite volume method, and the gas-water relative permeability of the heterogeneous hydrate-containing sediment core is obtained based on the steady-state method, thereby realizing cross-scale prediction of relative permeability from pore scale to core scale;

[0051] It not only establishes a bridge relationship between microscopic pore structure and core-scale gas-water relative permeability, and realizes the effective prediction of core-scale gas-water relative permeability of hydrate-containing sediments; it also reveals the influence of microscopic pore structure on core-scale gas-water relative permeability of hydrate-containing sediments.

[0052] It can not only effectively calculate the gas-water relative permeability of hydrate-containing sediments, but also take into account the local heterogeneity caused by the differences in pore structure at different spatial positions of hydrate-containing sediments, which is helpful for the production capacity prediction of natural gas hydrate reservoirs, provides more accurate and reliable simulation parameters for the numerical simulation of natural gas hydrate reservoirs, and lays a solid foundation for the efficient and safe development of natural gas hydrates. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] The present invention will be further described below with reference to the accompanying drawings and embodiments, in which:

[0054] Figure 1 It is a flow chart of the upscaling modeling method of gas-water relative permeability of hydrate-containing sediments provided by the present invention;

[0055] Figure 2 It is a CT scan of a hydrate-containing sediment core provided by the present invention;

[0056] Figure 3 It is a schematic diagram of selecting the approximate area and the characterization area of ​​the hydrate-containing sediment core provided by the present invention;

[0057] Figure 4 It is a schematic diagram of a unit body for characterizing fine pores, mesopores and coarse pores provided by the present invention;

[0058] Figure 5 It is a schematic diagram of the pore network model of fine pores, mesopores and macropores provided by the present invention;

[0059] Figure 6 It is a schematic diagram of an equivalent hydrate-containing sediment core model provided by the present invention;

[0060] Figure 7 It is a schematic diagram of the spatial distribution of permeability of an equivalent hydrate-containing sediment core model provided by the present invention;

[0061] Figure 8 It is a capillary pressure curve diagram of fine pore, medium pore and macropore area provided by the present invention;

[0062] Fig. 9 is a gas-water relative permeability curve diagram of fine pore, medium pore and macropore regions provided by the present invention;

[0063] Fig.10 It is a gas-water relative permeability curve diagram of an equivalent hydrate-containing sediment core provided by the present invention. DETAILED DESCRIPTION

[0064] In order to have a clearer understanding of the technical features, purposes and effects of the present invention, specific embodiments of the present invention are now described in detail with reference to the accompanying drawings.

[0065] Figure 1 The schematic diagram of the upscaling modeling method of gas-water relative permeability of hydrate-containing sediments of the present embodiment is shown. The upscaling modeling method of gas-water relative permeability of hydrate-containing sediments comprises the following steps: S1: obtaining a CT image of a hydrate-containing sediment core, and using a non-local mean filtering algorithm to obtain a three-dimensional digital core image; S2: obtaining the characterization areas of the fine pore area, the medium pore area and the coarse pore area and their porosity according to the three-dimensional digital core image; S3: obtaining the characterization areas of the fine pore area, the medium pore area and the coarse pore area according to the characterization areas of the fine pore area, the medium pore area and the coarse pore area, and using a pore network image processing and analysis tool S4: According to the characterization areas of fine pore area, medium pore area and coarse pore area and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, an equivalent hydrate-containing sediment core model is obtained; S5: According to the equivalent hydrate-containing sediment core model, core-scale single-phase fluid flow simulation and gas-water two-phase flow simulation are carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model.

[0066] Specifically, step S2 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S21: cropping the three-dimensional digital core image to obtain the approximate area of ​​the core; S22: using a histogram-based threshold algorithm to divide the approximate area to obtain the characterization area; S23: based on the characterization area, obtaining the porosity of each characterization area; S24: based on the porosity of each characterization area and the preset porosity interval, obtaining the characterization area of ​​the fine pore area, the medium pore area and the coarse pore area.

[0067] Specifically, step S3 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S31: according to the characterization areas of fine pore area, medium pore area and coarse pore area, using the pore network image processing and analysis tool, the pore structure information of the characterization areas of fine pore area, medium pore area and coarse pore area is obtained; S32: according to the pore structure information of the characterization areas of fine pore area, medium pore area and coarse pore area, using the porous medium pore network model, single-phase water pore network simulation and gas-water two-phase flow simulation are carried out respectively to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, as shown in the formula:

[0068]

[0069]

[0070]

[0071]

[0072] Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the relative permeability of the gas or water phase, k α is the effective permeability of gas or water in gas-water two-phase flow, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, w represents water, P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

[0073] Specifically, step S4 of the above-mentioned upscaling modeling method of gas-water relative permeability of hydrate-containing sediments includes the following steps: S41: According to the characterization areas of fine pore area, medium pore area and coarse pore area, the spatial position relationship of the three areas in the digital core image is utilized, and the corresponding characterization unit volumes are used to regroup to obtain the characterization unit volumes of fine pore area, medium pore area and coarse pore area; S42: According to the characterization unit volumes of fine pore area, medium pore area and coarse pore area, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area are mapped to the corresponding characterization unit volumes of fine pore area, medium pore area and coarse pore area to obtain an equivalent hydrate-containing sediment core model.

[0074] Specifically, step S5 of the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments includes the following steps: S51: According to the equivalent hydrate-containing sediment core model, a core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, such as the formula:

[0075]

[0076]

[0077]

[0078] Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term, t is time, x is the distance along the flow direction, k is the pore-scale absolute permeability, μ w is the viscosity of water, P w is the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate-containing sediment core model, q is the flow rate at the outlet of the equivalent hydrate-containing sediment core model at the time of obtaining stability, L is the length of the core along the flow direction, and A is the cross-sectional area; S52: According to the equivalent hydrate-containing sediment core model, a gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model, as shown in the formula:

[0079]

[0080]

[0081]

[0082]

[0083]

[0084]

[0085]

[0086] Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α represents the flow rate of water or gas at the outlet of the equivalent hydrate-containing sediment core at the time of obtaining stability, α represents gas or water, g represents gas, w represents water, and k rα is the relative permeability of gas and water at the pore scale, pα is the gas phase or water phase pressure, K rw is the water relative permeability of the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas flow rate.

[0087] The present invention also provides a system, including the following modules: a three-dimensional digital core image module, configured to obtain a CT image of a hydrate-containing sediment core, and obtain a three-dimensional digital core image using a non-local mean filtering algorithm; a characterization region division module, configured to obtain characterization regions and porosities of fine pore regions, medium pore regions, and coarse pore regions according to the three-dimensional digital core image; a physical property parameter calculation module, configured to obtain the characterization regions of the fine pore regions, medium pore regions, and coarse pore regions according to the characterization regions using a pore network image processing analysis tool and a porous medium pore network model; The equivalent hydrate sediment core model generation module is configured as follows: according to the characterization areas of the fine pore area, the medium pore area and the coarse pore area and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, the equivalent hydrate sediment core model is obtained; the flow simulation module: according to the equivalent hydrate sediment core model, the core-scale single-phase fluid flow simulation and the gas-water two-phase flow simulation are carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate sediment core model.

[0088] Specifically, the characterization area division module of the above-mentioned system is configured as follows: cropping the three-dimensional digital core image to obtain the approximate area of ​​the core; using a histogram-based threshold algorithm to divide the approximate area to obtain the characterization area; according to the characterization area, obtaining the porosity of each characterization area; according to the porosity of each characterization area and the preset porosity interval, obtaining the characterization areas of the fine pore area, the medium pore area and the coarse pore area.

[0089] Specifically, the physical property parameter calculation module of the above-mentioned system has the following configurations: according to the characterization areas of the fine pore area, the mesopore area and the coarse pore area, the pore network image processing and analysis tool is used to obtain the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area; according to the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area, the porous medium pore network model is used to respectively carry out single-phase water pore network simulation and gas-water two-phase flow simulation to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, as shown in the formula:

[0090]

[0091]

[0092]

[0093]

[0094] Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the gas-water relative permeability, k α is the effective permeability of gas or water in gas-water two-phase flow, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, w represents water, P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

[0095] Specifically, the equivalent hydrate sediment core model generation module of the above-mentioned system has the following configurations: according to the characterization areas of the fine pore area, the medium pore area and the coarse pore area, the spatial position relationship of the three areas in the digital core image is utilized, and the corresponding characterization unit volumes are used to reorganize to obtain the characterization unit volumes of the fine pore area, the medium pore area and the coarse pore area; according to the characterization unit volumes of the fine pore area, the medium pore area and the coarse pore area, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area are mapped to the corresponding characterization unit volumes of the fine pore area, the medium pore area and the coarse pore area to obtain the equivalent hydrate sediment core model.

[0096] Specifically, the flow simulation module of the above system is configured as follows: according to the equivalent hydrate-containing sediment core model, a core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, such as the formula:

[0097]

[0098]

[0099]

[0100] Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q wis the source term, t is time, x is the distance along the flow direction, k is the pore-scale absolute permeability, μ w is the viscosity of water, P w is the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate sediment core model, q is the flow rate at the outlet of the equivalent hydrate sediment core model at the time of obtaining stability, L is the length of the core along the flow direction, and A is the cross-sectional area. According to the equivalent hydrate sediment core model, the gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate sediment core model, as shown in the formula:

[0101]

[0102]

[0103]

[0104]

[0105]

[0106]

[0107]

[0108] Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α represents the flow rate of water or gas at the outlet of the equivalent hydrate-containing sediment core at the time of obtaining stability, α represents gas or water, g represents gas, w represents water, and k rα is the water relative permeability of the equivalent hydrate-containing sediment core, p α is the gas phase or water phase pressure, K rα is the water relative permeability of the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas flow rate.

[0109] In some embodiments, the above-mentioned upscaling modeling method for gas-water relative permeability of hydrate-containing sediments can also be implemented in the following manner.

[0110] The porous sediment core containing hydrates is scanned by CT instrument to obtain CT images. The non-local mean filtering algorithm in the Python language CV2 library is used to remove the noise in the image to make the image more uniform and smooth, and generate a three-dimensional digital core image, such as Figure 2 As shown, the black area represents pores, the light gray area represents matrix, and the dark gray area represents hydrates;

[0111] The entire 3D digital core image area is cropped to obtain the middle area as the approximate area of ​​the entire core, such as Figure 3 As shown, the core approximate area and the characterization area of ​​hydrate-bearing sediments are selected. The thick line large rectangular area represents the core approximate area, and the thin line small rectangle represents the characterization area, which includes three types of areas: coarse pores, medium pores, and fine pores.

[0112] According to the pixel information at different positions of the image, a threshold algorithm based on a histogram is used (the frequency of pixels is plotted into a histogram, and the threshold selection is determined based on the local minimum value of the histogram of the pixel frequency distribution) to determine the thresholds of hydrates, matrix and pores. The threshold is selected based on the local minimum value of the histogram of the pixel distribution. The horizontal axis of the image is the interval of pixels 0-255, and the vertical axis is the number of pixels. The value with the smallest number of pixels is used as the segmentation threshold. There are three intervals in total, namely, hydrate phase, matrix phase (sediment skeleton) and pore phase. Among them, the hydrate phase and matrix phase are classified into one category, namely "equivalent matrix"; on this basis, the above approximate area is divided to obtain the characterization area;

[0113] The porosity of each characterization area is calculated using the PoreSpy library in Python to obtain the porosity of each characterization area. In the process of calculating the porosity, the phase change of hydrates is not considered, and it is assumed that the hydrate sediment skeleton does not flow. Therefore, the sediment skeleton and hydrates are classified into one category, namely "equivalent matrix".

[0114] According to the porosity size (the porosity less than 0.32 is the fine pore area, the porosity between 0.32 and 0.37 is the medium pore area, and the porosity greater than 0.37 is the coarse pore area), the characterization area is divided into three areas: fine, medium, and coarse. A characterization unit body is selected from each of the above areas. When the porosity size of each area tends to a constant value, the area size at this time is considered to be the size of the characterization unit body; Figure 4 Shown are unit cells characterizing fine pore, mesopore, and coarse pore regions;

[0115] The pore network image processing and analysis tools, such as the Snow2 function in the PoreSpy library, are used to extract the pore structure information of the three characterization areas, such as Figure 5The pore network model of fine pores, medium pores and coarse pores is shown. The "ball" represents the pore and the "rod" represents the throat. The extracted pore structure information is imported into the porous media pore network model, such as the OpenPNM library, and the pore network model simulations of single-phase (water) and gas-water two-phase flow are carried out to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area.

[0116] Carry out single-phase water pore network simulation. During the simulation, fix the inlet and outlet pressures, record the flow rate when stable, and calculate the absolute permeability of each characterization area according to Darcy's formula;

[0117]

[0118] Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures respectively;

[0119] Carry out gas-water two-phase flow simulation, saturate the entire pore space with water, fix the inlet and outlet pressures, inject gas, and record the volume V of water at different times w , air flow rate q g and water flow rate q w , the water saturation can be expressed as:

[0120]

[0121] Where V is the pore volume, V w is the volume occupied by water, and the air-water relative permeability can be expressed as:

[0122]

[0123] In the formula, k rα is the relative permeability of gas to water at the pore scale, k α is the effective permeability of gas or water, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, and w represents water;

[0124] The capillary pressure was calculated using the Washburn formula;

[0125]

[0126] Where P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature;

[0127] The corresponding characterization units are used to represent the coarse pore, medium pore and fine pore regions. According to the spatial position relationship of the three regions in the digital core image, the corresponding characterization units are used to regroup and generate an equivalent hydrate-containing sediment core model. According to the spatial position relationship of the three regions in the digital core image, the corresponding characterization units are used to regroup and generate an equivalent hydrate-containing sediment core model, such as Figure 6 The figure shows the equivalent hydrate-containing sediment core model. The dark gray cubes represent the characterization units of the coarse pore area with a porosity greater than 0.37, the light color represents the characterization units of the coarse pore area with a porosity between 0.32 and 0.37, and the dark color represents the characterization units of the fine pore area with a porosity less than 0.32. Figure 7 The permeability spatial distribution of the equivalent hydrate-containing sediment core model is shown), capillary pressure (such as Figure 8 The capillary pressure curves of fine pores, medium pores and macropores are shown) and the gas-water relative permeability (such as Fig. 9 The figure shows the gas-water relative permeability curves of fine pore, medium pore and macropore regions) mapping (the macropore region represents the unit porosity, absolute permeability, gas-water relative permeability and capillary pressure are assigned to the dark grey small squares, the medium pore region represents the unit porosity, absolute permeability, gas-water relative permeability and capillary pressure are assigned to the light small squares, the fine pore region represents the unit porosity, absolute permeability, gas-water relative permeability and capillary pressure are assigned to the dark small squares) to the corresponding positions of the equivalent hydrate-bearing sediment core model;

[0128] Core-scale single-phase (water) and gas-water two-phase flow simulations were performed on the equivalent hydrate-containing sediment core model. The seepage equation was solved using the finite volume method. The gas-water relative permeability of the equivalent hydrate-containing sediment core model was obtained based on the steady-state method (changing different gas-water ratios and repeating the above gas-water two-phase simulation to obtain a series of gas-water relative permeability values ​​and water saturation values), thereby achieving cross-scale prediction of gas-water relative permeability from pore scale to core scale.

[0129] A constant pressure (boundary condition) is applied to the equivalent hydrate-containing sediment core model to simulate the core-scale single-phase (water) flow. According to the mass conservation equation, the following equation can be obtained:

[0130]

[0131] In the formula, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term, P w is the water phase pressure, G is the gravitational acceleration. According to Darcy's law, we can get:

[0132]

[0133] The finite volume method is used to solve the above mass conservation equation and Darcy's equation to obtain the flow rate q of the equivalent hydrate-containing sediment core outlet at the stable moment, and the absolute permeability is calculated according to Darcy's law;

[0134]

[0135] Applying a constant pressure to the equivalent hydrate-containing sediment core model and injecting a constant gas-water ratio to simulate the core-scale gas-water two-phase flow, the following equation can be obtained based on the mass conservation equation and Darcy equation:

[0136]

[0137]

[0138] The finite volume method is used to solve the above mass conservation equation and Darcy equation to obtain the flow rate q and water saturation S of the equivalent hydrate-containing sediment core outlet at the stable moment. w The gas-water relative permeability was obtained using Darcy's law using the ratio of the volume of water to the pore volume of the equivalent hydrate-containing sediment core;

[0139]

[0140]

[0141] Based on the steady-state method (changing different gas-water ratios and repeating the above gas-water two-phase simulation to obtain a series of gas-water relative permeability values ​​and water saturation values), the gas-water relative permeability of the equivalent hydrate-containing sediment core model is obtained, and the cross-scale prediction of the gas-water relative permeability of hydrate-containing sediments from the pore scale to the core scale is realized, such as Fig.10 Shown is the gas-water relative permeability curve of the equivalent hydrate-containing sediment core.

[0142] The embodiments of the present invention are described above in conjunction with the accompanying drawings, but the present invention is not limited to the above-mentioned specific implementation modes, which are merely illustrative rather than restrictive. Under the guidance of the present invention, ordinary technicians in this field can also make many forms without departing from the scope of protection of the present invention and the claims, all of which are within the protection of the present invention.

Claims

1. A method for upscaling gas-water relative permeability modeling of hydrate-containing sediments, characterized in that: The following steps are involved: S1: Obtain CT images of hydrate-containing sediment cores and use non-local mean filtering algorithm to obtain three-dimensional digital core images; S2: according to the three-dimensional digital core image, obtaining the characterization areas and porosities of the fine pore area, the medium pore area and the coarse pore area; S3: according to the characterization areas of the fine pore area, the mesopore area and the coarse pore area, using a pore network image processing analysis tool and a porous media pore network model, obtaining the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area; S4: obtaining an equivalent hydrate-containing sediment core model according to the characterized regions of the fine pore region, the medium pore region and the coarse pore region and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterized region; S5: According to the equivalent hydrate-containing sediment core model, core-scale single-phase fluid flow simulation and gas-water two-phase flow simulation are carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model; Step S5 includes the following steps: S51: Based on the equivalent hydrate-containing sediment core model, a core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, such as the formula: Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term, t is time, x is the distance along the flow direction, k is the pore-scale absolute permeability, μ w is the viscosity of water, P w is the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate-containing sediment core, q is the flow rate at the outlet of the equivalent hydrate-containing sediment core at the moment of obtaining stability, L is the length of the core along the flow direction, and A is the cross-sectional area; S52: According to the equivalent hydrate-containing sediment core model, a gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model, as shown in the formula: Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α Indicates the amount of water and gas injected, α indicates gas or water, g indicates gas, w indicates water, and k rα is the relative permeability of gas and water at the pore scale, p α is the gas phase or water phase pressure, K rw is the water relative permeability of the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas flow rate.

2. The upscaling modeling method for gas-water relative permeability of hydrate-containing sediments according to claim 1, characterized in that: Step S2 includes the following steps: S21: cutting the three-dimensional digital core image to obtain an approximate area of ​​the core; S22: using a threshold algorithm based on a histogram to divide the approximate area to obtain a characterization area; S23: obtaining the porosity of each characterization region according to the characterization region; S24: obtaining characterization regions of fine pore region, medium pore region and coarse pore region according to the porosity of each characterization region and the preset porosity interval.

3. The upscaling modeling method for gas-water relative permeability of hydrate-containing sediments according to claim 1, characterized in that: Step S3 includes the following steps: S31: according to the characterization areas of the fine pore area, the mesopore area and the coarse pore area, using a pore network image processing and analysis tool, obtaining pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area; S32: Based on the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area, a single-phase water pore network simulation and a gas-water two-phase flow simulation are respectively carried out using a porous media pore network model to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, as shown in the formula: Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the relative permeability of the gas phase or water phase, α represents gas or water, g represents gas, w represents water, and k α is the effective permeability of gas or water in gas-water two-phase flow, k f is the permeability of single-phase flow, P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

4. The upscaling modeling method for gas-water relative permeability of hydrate-containing sediments according to claim 1, characterized in that: Step S4 includes the following steps: S41: according to the representation regions of the fine pore region, the medium pore region and the coarse pore region, using the spatial position relationship of the three regions in the digital core image, using the corresponding representation unit volumes to obtain the representation unit volumes of the fine pore region, the medium pore region and the coarse pore region; S42: According to the characterization unit cells of the fine pore region, the medium pore region and the macropore region, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization region are mapped to the characterization unit cells of the corresponding fine pore region, the medium pore region and the macropore region to obtain an equivalent hydrate-containing sediment core model.

5. A system, characterized in that: Includes the following modules: The three-dimensional digital core image module is configured to: obtain a CT image of a hydrate-containing sediment core, and obtain a three-dimensional digital core image using a non-local mean filtering algorithm; The characterization region division module is configured to: obtain the characterization regions and porosities of the fine pore region, the medium pore region and the coarse pore region according to the three-dimensional digital core image; The physical property parameter calculation module is configured to: obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area according to the characterization areas of the fine pore area, the mesopore area and the coarse pore area by using a pore network image processing analysis tool and a porous medium pore network model; An equivalent hydrate-containing sediment core model generation module is configured to: obtain an equivalent hydrate-containing sediment core model according to the characterization areas of the fine pore area, the medium pore area and the coarse pore area and the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization area; Flow simulation module: according to the equivalent hydrate-containing sediment core model, core-scale single-phase fluid flow simulation and gas-water two-phase flow simulation are carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model; The flow simulation module has the following configurations: According to the equivalent hydrate-containing sediment core model, core-scale single-phase fluid flow simulation is carried out, and the single-phase seepage equation is solved using the finite volume method to obtain the absolute permeability of the equivalent hydrate-containing sediment core model, as shown in the formula: Among them, ρ w is the density of water, φ is the porosity, v is the flow velocity, q w is the source term, t is time, x is the distance along the flow direction, k is the absolute permeability at the pore scale, μ w is the viscosity of water, P w is the water phase pressure, G is the gravitational acceleration, K is the absolute permeability of the equivalent hydrate-containing sediment core model, q is the flow rate at the outlet of the equivalent hydrate-containing sediment core model at the moment of obtaining stability, L is the length of the equivalent core along the flow direction, and A is the cross-sectional area; According to the equivalent hydrate-containing sediment core model, a gas-water two-phase flow simulation is carried out to obtain the absolute permeability and gas-water relative permeability of the equivalent hydrate-containing sediment core model, as shown in the formula: Among them, ρ α Indicates the density of water or gas, S α Indicates water saturation or gas saturation, v α Indicates the flow rate of water or gas, q α represents the flow rate of water or gas at the outlet of the equivalent hydrate-containing sediment core model at the time of obtaining stability, α represents gas or water, g represents gas, w represents water, μ α Indicates the viscosity of gas or water, q w Indicates the amount of water injected, k rα is the pore-scale gas-water relative permeability, p α is the gas phase or water phase pressure, K rw is the water relative permeability of the equivalent hydrate-containing sediment core, P in is the inlet pressure, P out is the outlet pressure, K rg is the gas relative permeability of the equivalent hydrate-containing sediment core, P0 is the atmospheric pressure, μ g is the viscosity of the gas, q g is the gas outlet flow rate at the stable moment.

6. The system according to claim 5, characterized in that The representation area division module has the following configurations: Cutting the three-dimensional digital core image to obtain an approximate area of ​​the core; Using a threshold algorithm based on a histogram, the approximate region is divided to obtain a characterization region; According to the characterization regions, the porosity of each characterization region is obtained; According to the porosity of each characterization region and the preset porosity interval, characterization regions of the fine pore region, the medium pore region and the coarse pore region are obtained.

7. The system according to claim 5, characterized in that The physical property parameter calculation module has the following configurations: According to the characterization areas of the fine pore area, the mesopore area, and the coarse pore area, using a pore network image processing and analysis tool, pore structure information of the characterization areas of the fine pore area, the mesopore area, and the coarse pore area is obtained; According to the pore structure information of the characterization areas of the fine pore area, the mesopore area and the coarse pore area, the single-phase water pore network simulation and the gas-water two-phase flow simulation are carried out respectively using the porous media pore network model to obtain the absolute permeability, capillary pressure and gas-water relative permeability of each characterization area, as shown in the formula: Where k is the absolute permeability, q is the flow rate, μ w is the viscosity of water, L is the length of the region along the flow direction, A is the cross-sectional area, P in and P out are the inlet and outlet pressures, S w is water saturation, V is pore volume, V w is the volume occupied by water, k rα is the gas-water relative permeability, k α is the effective permeability of gas or water, k f is the permeability of single-phase flow, α represents gas or water, g represents gas, w represents water, and P c is the capillary pressure, γ and θ are the air-water interfacial tension and contact angle, respectively, and r is the radius of curvature.

8. The system according to claim 5, characterized in that The equivalent hydrate-containing sediment core model generation module has the following configurations: According to the representation regions of the fine pore region, the medium pore region and the macropore region, the spatial position relationship of the three regions in the digital core image is utilized, and the corresponding representation unit volumes are reassembled to obtain the representation unit volumes of the fine pore region, the medium pore region and the macropore region; According to the characterization unit cells of the fine pore region, the medium pore region and the macropore region, the porosity, absolute permeability, capillary pressure and gas-water relative permeability of each characterization region are mapped to the corresponding characterization unit cells of the fine pore region, the medium pore region and the macropore region to obtain an equivalent hydrate-containing sediment core model.

Images