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Collaborating Authors
Results
Permeability Prediction Considering Surface Diffusion for Gas Shales by Lattice Boltzmann Simulations on Multi-Scale Reconstructed Digital Rocks
Ning, Yang (University of Houston) | He, Shuai (University of Houston) | Liu, Honglin (PetroChina Research Institute of Petroleum Exploration & Development, Langfang Branch) | Wang, Hongyan (PetroChina Research Institute of Petroleum Exploration & Development, Langfang Branch) | Qin, Guan (University of Houston)
Abstract The apparent permeability function in kerogen is developed by combining effects of viscous flow, Knudsen diffusion, and surface diffusion, in which the surface diffusion is defined as the transport of adsorbed gas due to the difference of adsorbed gas concentrations. The concentration of the adsorbed gas is quantified by the monolayer adsorption coverage and the specific surface area in shale. Weighting coefficients of viscous flow and Knudsen diffusion are determined based on the probabilities of collisions frequency between gas molecules and between gas molecules and pore walls. Analyzing the effect of surface diffusion, we found that the mass flux contribution of surface diffusion was dependent on many parameters that include pressure, temperature, pore size, specific surface area, etc. The apparent permeability function is further incorporated into the generalized lattice Boltzmann method (LBM) for porous media. A 3D nanometer-scale kerogen digital rock including macro-pores and larger-scale digital rocks including mineralogical components are reconstructed based on the focused ion beam-scanning electron microscopy (FIB-SEM) and Nano-CT experiments, respectively. The kerogen structures (1.53ฮผm3) from FIB-SEM experiments distinguish macro-pores (>10nm) and kerogen solids. Kerogen solid is permeable as micro/meso-pores (1-10nm) exist in nature but are lost by the FIB-SEM experiment. The apparent permeability function is assigned locally on permeable kerogen solids. In Nano-CT digital rocks (413ฮผm3), 4 different mineralogical components have been differentiated. Rock/fluid properties of shales in nanometer scale and micrometer scale are obtained by performing LBM simulations on digital rocks. The relations of methane permeability in kerogen with pressure, temperature, average pore diameter, and specific surface area have been investigated for the FIB-SEM digital rock. In addition, we have investigated the effects of organic contents on methane permeability in shale by comparing the simulation results of 3 different Nano-CT digital rocks.
- Asia (1.00)
- North America > United States > Texas (0.46)
Transport Properties of Natural Gas in Shale Organic and Inorganic Nanopores Using Non-Equilibrium Molecular Dynamics Simulation
He, Shuai (University of Houston) | Ning, Yang (University of Houston) | Chen, Tianluo (University of Houston) | Liu, Honglin (Research Institute for Petroleum Exploration & Development - Langfang Branch, PetroChina Company Limited) | Wang, Hongyan (Research Institute for Petroleum Exploration & Development - Langfang Branch, PetroChina Company Limited) | Qin, Guan (University of Houston)
Abstract One of the most important characteristics of shale gas formation is that the majority of the natural gas in both organic and inorganic nanopores exists as adsorbed gas and, due to the pressure draw down, the desorbed gas flows into the adjacent fracture network from the shale matrix. Therefore, numerical investigations on the transport behavior of natural gas in the nanopores become increasingly crucial for better understanding the shale gas production performance due to the limitations of current experimental measurements. In this paper, we applied boundary-driven non-equilibrium molecular dynamics (BD-NEMD) simulation to estimate natural gas transport diffusivity coefficients in both organic and inorganic nanopores. Type II kerogen molecules and montmorillonite clay molecules are used to model the nano-channel with various sizes and methane is used to model natural gas. Driven by an external force, high- and low-density gas regions have been formed and constant flow rate has been established as the system reaches steady-state. Pressure-dependent transport diffusivity coefficients of methane can be then determined based on 1st-order Fick's law. Due to the work done by the external force, the temperature of fluid will inevitably increase and introduce certain artifacts to the diffusivity coefficients. Therefore, fluid temperature must be carefully controlled during the simulation to mimic real isothermal flow experiments. Both convection and diffusion contribute to the gas transport in nano-channel. Results indicate that the molecular mean free path is smaller than the free gas region due to the nano-scale confinement effect. Transport diffusivity coefficients depend on Knudsen number as well as pore geometry. In the continuum regime (Kn < 0.1), transport diffusivity coefficients are mainly dominated by convection and independent on pore size. In the transition regime (0.1 < Kn < 10), gas transport can be estimated by Knudsen diffusion that transport diffusivity coefficients are size-dependent. Meanwhile, in the organic nanopore, similar correlation is observed with smaller characteristic Knudsen number. Deviations may be caused by the surface roughness.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (0.74)
Abstract In shale formations, natural gas flows either through nano-scale pores or fractures during production period. Darcy's law cannot effectively describe such transport phenomena due to its continuum assumption. Alternatively, kinetic-based lattice Boltzmann method (LBM) becomes a strong candidate of simulating organic-rich shale reservoir that contains a large amount of nano-scale pores. Among various LBM models, multiple-Relaxation-Time (generalized) LBM is considered as one of the most efficient models regarding its theories, selections of parameters, and numerical stability. For gas flow in a confined system, its molecular mean free path depends on not only the size of the confined system, but also the distance of gas molecules from solid walls. A large amount of natural gas is believed to be stored in extremely small organic pores, and adsorption in shale has a significant influence for gas transport in production. In this paper, we incorporated adsorption into generalized LBM model in order to capture the natural gas flow in organic nano-pores. Many factors are believed to control the flow mechanism in such pores, such as the size of organic pores, specific surface area, adsorptive strength, and so on. Generalized LBM results shows a great agreement with available data for high Knudsen flows between two-dimensional parallel plates. Accounted the effect of adsorption, flow phenomena are investigated by varying different controlling factors in both simple and complex structures. Introduction Shale gas has been becoming a significant source of unconventional natural gas. The production of shale gas mainly depends on its characteristics, such as the pore distribution, organic richness, natural/factitious fractures, etc. A significant portion of shale gas is stored in kerogen pores that are ranging 2nm to 50 nm [1, 2, 3]. Consequently, it is essential to understand natural gas flow in nanopores to be able to predict long-term shale gas production as well as shale gas reserves.
- North America > United States (1.00)
- Asia (0.68)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)