• Energy Research

AbstractPredicting CO2 plume migration is an important aspect for the geological sequestration of CO2. In the absence of experimental data, the storage performance of CO2 geo‐storage can be assessed through the dynamic modelling of the fluid flow and transport properties of the rock‐fluid system using empirical formulations. Using the van Genuchten empirical model, this study documents a Darcy flow modelling approach to investigate different aspects of CO2 drainage in a sandstone formation with interbedded argillaceous (i.e. mudstone) units. The numerical simulation is based on the Sleipner gas field storage unit where several thin argillite layers occur within the sandstone of the Utsira Formation. With respect to forward modelling simulations that have used Sleipner Formation as a case study, it is noted that previous attempts to numerically calibrate the CO2 plume migration to time‐lapse seismic dataset using software governed by Darcy flow physics achieved poor results. In this study, CO2‐brine buoyant displacement pattern is simulated using the ECLIPSE ‘black oil’ simulator within a two‐dimensional axisymmetric geometry and a three‐dimensional Cartesian coordinate system. This investigation focussed on two key parameters affecting CO2 migration mobility, namely relative permeability and capillary forces. Examination of these parameters indicate that for the gravity current of CO2 transiting through a heterogeneous siliciclastic formation, the local capillary forces in geologic units, such as mudstone and sandstones, and the relative permeability to the invading fluid control the mass of CO2 that breaches and percolates through each unit, respectively. In numerical analysis, these processes influence the evaluation of structural and residual trapping mechanisms. Consequently, the inclusion of heterogeneities in capillary pressure and relative permeability functions, where and when applicable, advances a Darcy modelling approach to history matching and forecasting of reservoir performance. Results indicate that there is a scope for a revision of the basic premise for modelling flow properties in the interbedded mudstones and the top sand wedge at the Sleipner Field when using Darcy flow simulators. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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.

Abstract In the application of two-phase flow in porous media within the context of CO2 sequestration, a non-wetting phase is used to displace a wetting phase residing in-situ to the maximum extent through a network of pore conduits. The storage performance of this physical process can be assessed through numerical simulations where transport properties are usually described using the Brooks & Corey (BC) or van Genuchten (vG) model. The empirical constant, namely the pore geometry index, is a primary parameter in both of these models and experimental evidence shows a variation in the value of this empirical constant. It is, therefore, essential to cast this empirical constant into a ternary diagram for all types of clastic porous media to demarcate the efficiency of two-phase flow processes in terms of the pore geometry index (PGI). In doing so, this approach can be used as a tool for designing more efficient processes, as well as for the normative characterisation of two-phase flow, taking into consideration the predominance of capillary pressure or relative permeability effects. This concept is based on the existence of a PGI estimation for clastic sediments, for which the value for 12 sediment mixtures fall between 1.01 and 3.00. Statistical data obtained from soil physics is used for developing and validating numerical models where a good match is observed in numerical simulations. In this context, a new methodology for the effective characterisation of PGI for different clastic rocks is proposed. This paper presents theoretical observations and continuum-scale numerical simulation results of a PGI characterisation for the prediction of the hydraulic properties of clastic reservoir rocks. The effect of key parameters in the vG empirical model, such as the pressure strength coefficient and the PGI, is incorporated into the simulation analysis. In particular, the model is used to investigate the effects of parameter representation on CO2 storage performance in a saline aquifer. Subsequent analysis shows that the PGI is a very important parameter for defining the flow characteristics of simulation models. It can also be flexibly changed for each rock type and this approach may thus be practical when simulating the evolution of CO2 plume in reservoirs with sedimentary heterogeneities, such as intra-aquifer aquitard layers or graded beds. The use of the realistic PGI boundaries promises a more precise description of the hydraulic behaviour in sandstones and shale when using either the BC or vG model.