Effect of sedimentary heterogeneities in the sealing formation on predictive analysis of geological CO2 storage

Abstract

Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection. This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions. The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration.

Characterising the role of parametric functions in the van Genuchten empirical model on CO2 storage performance

“…In the absence of site-specific data on capillary pressure, relative permeability and pore geometry distribution, the study proposes a parameterisation scheme for the pore geometry index that can serve as a tool for modelling hydraulic heterogeneities in clastic formations. For the sake of a comprehensive demonstration, this methodology has been applied to flow simulation through stratigraphic heterogeneities such as graded bedding in the reservoir (Onoja and Shariatipour, 2018) and transitional lithologies in the seal (Onoja et al, 2019). The authors observed that the exclusion of relative permeability and capillary heterogeneities in the dynamic modelling of CO2 sequestration can underestimate the storage performance of the reservoir and the seal.…”

Carbon Dioxide (CO2) Dissolution Efficiency During Geological Carbon Sequestration (GCS) in Randomly Stratified Formations

“…Other authors (Doughty & Pruess, 2004; Doughty et al., 2001; Gershenzon, Ritzi, et al., 2015) have only analyzed dissolution trapping in a few idealized depositional settings. In numerical modeling studies, the small‐scale variability of permeability is often not explicitly represented (Birkholzer et al., 2009; Hayek et al., 2009; Lee et al., 2010; Onoja et al., 2019; Pruess & Nordbotten, 2011; Rasmusson et al., 2015). Qualitative or quantitative analysis of the impact of discounting the small‐scale variability on modeling prediction of geological carbon sequestration has not been reported.…”

Parametric study on the integrity of wellbores in CO2 storage sites

“…Once the CO 2 is injected in underground formations, it begins moving laterally beneath the caprock generally towards less deeper locations [9][10][11][12][13]. Therefore the CO 2 plume would encounter other wells as it moves along its path.…”