CO2 Injection Simulation in Thalassinoides-bearing rocks: Implications for geological carbon sequestration

Geological carbon sequestration (GCS) is a key technology for mitigating CO₂ emissions from hard-to-abate industrial sources, it has been tested in various subsurface formations including basalts, coal seams, shales, carbonate rocks, sandstones and salt formations.  With carbonates and sandstones being the most widely utilized reservoirs for long-term storage. Although these formations may exhibit favorable porosity and permeability, they are typically heterogenous because of various depositional processes and diagenesis modifications. Such heterogeneity has significant impact on CO₂ injectivity, migration, and storage efficiency.

Bioturbation, the reworking and modification of sediments by organisms represents an additional and often underexplored source of heterogeneity in both carbonate and sandstone reservoirs. Burrow networks can locally enhance or impede fluid flow, thereby influencing CO₂ injectivity, migration behavior, and storage performance. This study investigates the role of bioturbation, represented by Thalassinoides networks, in controlling CO₂ storage behavior in tight sedimentary strata, with the Upper Jurassic Hanifa Formation of Saudi Arabia serving as a representative case study.

High-resolution X-ray computed tomography scans of Thalassinoides-bearing carbonate rock samples were used to capture the three-dimensional geometry and connectivity of the burrow networks. These data served as training images for multipoint statistics modeling, allowing the construction of a realistic fine-scale rock model that preserve burrow morphology and spatial continuity. To facilitate dynamic flow simulations, the model was upscaled to a coarser grid while maintaining the nature of the burrow network. In this study, three different burrow permeability values (1, 10, and 100 mD) were tested while maintaining the matrix permeability constant (0.1 mD). CO₂ injection simulations were performed using a numerical reservoir simulator, testing the three different scenarios: 1. high burrow permeability (100 mD), 2. medium burrow permeability (10 mD), and 3. low burrow permeability (1 mD).

The results demonstrate that the permeability contrast between the Thalassinoides burrow network and its surrounding matrix has a major control on CO₂ plume diffusion. A high permeability contrasts promote rapid injectivity while leading to a strong channelized flow confined to the burrow networks with poor CO₂ penetration into the matrix. A medium permeability contrast allows for a balanced CO₂ flow and efficient CO₂ diffusion into the matrix. A low permeability contrast results in a more homogeneous CO₂ diffusion and an improved storage efficiency due to high penetration into the rock matrix.

These findings highlight the necessity of incorporating bioturbation-induced heterogeneity into GCS assessments. Explicitly accounting for ichnological assemblages can improve simulation accuracy, optimize injection strategies, and support more robust site selection for GCS projects. Similar refinements can be applied in Saudi Arabia and in analogous sedimentary settings worldwide.