Speaker
Description
Shale reservoirs exhibit a wide distribution of nanopore sizes, ranging from ultrafine pores of roughly 5 nm to larger pores exceeding several hundred nanometers. At the smallest scales, methane adsorption becomes a dominant storage mechanism. To quantify this effect, molecular simulations coupled with an equation of state are employed to characterize CH₄ adsorption in nanopores of various sizes, and the results are incorporated into a lattice Boltzmann (LB) free-energy model via a calibrated fluid–wall interaction formulation. The simulations reveal that adsorption can enhance methane storage by 10–25% in pores smaller than ~20 nm, whereas its influence becomes minimal (<3%) in pores larger than approximately 40 nm.
This scale-dependent behavior allows a natural transition to the flow regime: pores larger than ~100 nm, which constitutes the primary connected flow pathways in shale, but exhibits negligible adsorption effects. Building on this insight, pressure-driven flow and displacement processes are simulated using a multiple-relaxation-time LB model with a combined bounce-back/specular-reflection boundary treatment and regularization algorithm. The model is applied to investigate CO₂ and H₂ transport and storage in depleted shale gas reservoirs, focusing on how these injected gases move through with slippage velocity and displace residual methane in the larger, flow-dominant pore networks. Simulations quantify velocity fields, mass fluxes, apparent permeability, pressure drop, and displacement efficiency, revealing distinct CH₄ displacement mechanisms driven by the contrasting molecular properties of CO₂ and H₂.
Together, these two complementary components (adsorption analysis in ultrafine nanopores and flow modeling in larger and connected pores) provide a coherent, scale-consistent framework for understanding CH₄/CO₂/H₂ storage and transport across the hierarchical pore structure of shale formations.
| Country | USA |
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