Pore-scale modelling of CO2 -brine flow properties at In Salah, Algeria

Abstract

Abstract We present petrophysical data derived from pore-network modelling of CO2-brine pore systems from the Krechba CO2 Storage Site (part of the In Salah Gas Joint Venture project operated by BP, Sonatrach and Statoil). The Carboniferous sandstone reservoir formation has relatively low permeability (c. 10 mD) and is characterized by abundant and variable cementation–mainly quartz, patchy carbonates, grain-coating chlorites and pyrite. These petrographic characteristics make obtaining measurements and estimation of single and multiphase flow properties challenging. Pore-scale modelling is an important new tool which can supplement special core analysis measurements by providing single and two phase flow functions for a range of rock and pore types. CO2/water relative permeability measurements have been carried out on four composite core plugs at reservoir conditions (95°C and 180 bars pore pressure). We have reviewed these experimental data and compared them to new predictions from several pore-scale reconstructions of the matching rock samples. First porosity, absolute permeability and formation factor were calculated and compared experimental data. Pore-networks were then extracted from the rock models and used as inputs to the simulation of CO2/water displacements. Primary drainage and waterflooding sequences were simulated to establish end-point saturations (i.e. Swi and trapped CO2 saturation), capillary pressure and relative permeability curves. Very good agreement was found between the experimental results and those derived from calculations of petrophysical parameters on rock models and multiphase flow simulations through their respective pore-networks. Calculated permeability and porosity match the values estimated from the available logs, and the calculated average cementation exponent (m) for the three reconstructed samples is 2.05, comparable with the experimental value of 1.98. Swi values obtained from the simulations range from 0.29 to 0.34, similar but slightly lower than those obtained from the steady-state experimental study–0.39 to 0.44. The simulated residual CO2 saturation ranges from 36% to 44%. The capillary trapping ensures that part of the injected CO2 will stay disconnected as isolated CO2 clusters in the pore space. These values are comparable to the residual gas saturation estimated from the experiments (from 15 to 40 %). Differences between experiments and models can be related to differences in pore types which are better defined in the pore-network models. We conclude that pore-scale modelling is able to reproduce and supplement special core analysis experiments, even when the simulations are based on relatively simple assumptions, such as non-reactive and immiscible fluids. In addition, pore-scale modelling allows the correlation of end-points with the geometry, topology and morphology of the pore space of the rock, allowing us to improve the basic understanding of CO2 trapping mechanisms in heterogeneous formations.