InterPore2026

Transport of dissolved CO2 in low porosity fractured geological formation using a discrete fracture network approach

22 May 2026, 14:45

15m

Oral Presentation (MS03) Flow, transport and mechanics in fractured porous media MS03

Speaker

Mrs Sudhishna P N R L (Department of Chemical Engineering, Indian Institute of Technology Kharagpur, West Bengal-721302)

Description

P N R L Sudhishna a, Sourav Mondal a*, Tridib Kumar Mondal b, Chris Aldrich c, Milin K Shah c
a Department of Chemical Engineering, Indian Institute of Technology Kharagpur, West Bengal-721302.
b Geological Studies Unit, Indian Statistical Institute, Kolkata, West Bengal-700108.
c Western Australian School of Mines, Mineral, Energy and Chemical Engineering, Curtin University, Bentley, WA 6102, Australia.

Understanding the fluid flow behaviour in unconventional geological reservoirs is challenging because they comprise a complex fracture network, particularly in shale reservoirs such as tight sandstones and shale rocks, as well as in basalt rocks. Due to their low matrix permeability and low porosity, shale reservoirs rely on induced and natural fracture networks to facilitate fluid flow transport. These fractured, porous media are challenging to model or analyse due to their heterogeneity and non-linear flow behaviour. As a result, understanding CO₂ injection behaviour in these tight formations is inherently complex. Fluid flow in fracture networks in rocks is relevant to various scientific and industrial problems and processes, which have received considerable attention (Cook, 1992; Liu and Jiang, 2018; Sadhukhan et al., 2012). It is well established that the crustal fluid flows are governed by the pre-existing anisotropy (fractures/foliations) in the rocks under a specific state of stress condition. Most of the rock masses contain complex, interconnected networks of fractures, which are often conduits for fluid-solid interactions because of their high transmissivity, and their presence is critical in the subsurface processes such as recovery of hydrocarbons and geothermal fluids, and in mediating the evolution of fault zones and formation of hydrothermal mineral deposits (Faoro et al., 2009). When CO2-enriched fluids are injected into shale formations, complex geochemical reactions (Seyyedi et al., 2020) occur, such as mineral dissolution, precipitation formation and matrix deformation, which in turn alter the permeability and fracture properties of the subsurface shale rock as shown in Fig.1. Understanding behavior of fluids within these complex fracture patterns is essential for various subsurface applications, including enhanced oil recovery (EOR), geothermal energy, water well production enhancement, CO2 sequestration in a porous medium and gas hydrates (Liu and Jiang, 2018). To study such systems, researchers have employed experimental, theoretical, and primarily numerical simulations. Among the various numerical modelling techniques, such as the Channelling Network (CN) model, the Discrete Fracture Network (DFN) model, dual-porosity model, etc., the DFN approach is particularly chosen for low-permeability shale reservoirs (Dershowitz et al., 2010; Kalantari, 2020; Sun et al., 2024; Romano et al., 2025). In this study, we present a discrete fracture network-based numerical approach in COMSOL Multiphysics to investigate CO2 injection into a low-porosity geological rock formation characterized by a complex fracture network. The work focuses on understanding the resulting fluid-flow behaviour and evaluating how fracture connectivity and pressure-driven flow contribute to the enhanced permeability within the formation.
Figure 1: (a) represents the geologic cross-section of subsurface CO2 sequestration with a discrete fracture network, heterogeneity, reservoir caprock system, and associated flow paths (DePaolo and Cole, 2013); (b) DFN patterns of reservoir rock from the COMSOL simulation study.