Challenges for measuring two-phase flow properties on sandstones: focus on mineralogical changes and heterogeneity
Résumé
Multiphase flow properties of a porous media give insight on the way different fluids can flow in a given rock. In that sense, they are of first importance for a proper understanding of the behaviour of an aquifer where injected fluids differ from the native ones (natural gas seasonal storage, enhanced oil recovery, geological storage of hydrogen, geological storage of carbon dioxide). By multiphase flow properties, one mostly means two different properties: capillary pressure and relative permeability. These properties have been shown to be dependent on the rock itself (wetting character), on the fluids considered and on the conditions at which they are measured, namely the pressure, temperature and the ratio between the different forces (e.g. capillary and advective forces). The research effort on CO2 geological storage during the past fifteen years has given rise to the study of the CO2/brine system in porous media. The main purpose of these works was to gather data for different rocks and conditions but also to understand the differences, if they exist, of this two-phase flow system compared to other ones. All these different works have also lead to the progressive building of best practices adapted to CO2/brine system at storage depth conditions. In this study, new measurements have been performed on Triassic sandstone from Paris Basin, France following these best practices. A full characterization of one sample has been done using the two-phase flow core flooding apparatus with Magnetic Resonance Imaging, designed and developed at Tsinghua University, China: porosity, permeability, capillary pressure, relative permeability (with hysteresis between drainage and imbibition) and residual trapping capacities have been assessed. New methodologies for relative permeability and capillary pressure (joint determination of capillary pressure and relative permeability curves using core-flooding technique by Pini and Benson, 2013, in Water Resour. Res.) and classical ones (steady-state measurement of relative permeability, mercury injection capillary pressure) have been undertaken. The extensive data set obtained allows discussing the challenges to be faced when doing such measurements. First the uncertainties linked with the different measurements have been quantified. In addition to that important aspect, we focused on two other challenges that seem of primary importance when the obtained parameters and curves have to be used for large scale storage assessment: 1) The variability of the parameters (especially two-phase flow ones) over time: in our case, some mineral dissolution seemed to occur during the experiments campaign and it has been possible to quantify the associated changes in absolute and two-phase flow properties. The evolution of each parameter has been studied independently and has shown an increase in porosity, absolute permeability and CO2-relative permeability and a decrease in capillary pressure. The pore structure modifications has been confirmed with regular MR measurements during the experimental campaign, and some mineralogical analyses have been done on initial and after-experiment rock samples to understand the causes of the observed changes in flow properties. 2) The heterogeneity within the sample: the sample used for the experimentations being slightly heterogeneous, we have been able to study the impact of these heterogeneities in the two-phase flow curves measurement. More precisely, a combination of different ways of measuring capillary pressure and of two-phase flow modelling enable a better understanding of the differences in capillary pressure along the core.