Connected pathway relative permeability from pore-scale imaging of imbibition

S Berg,M Rücker,H Ott,A Georgiadis,H Van Der Linde,F Enzmann,M Kersten,R.T Armstrong,S De With,J Becker,A Wiegmann

doi:10.1016/j.advwatres.2016.01.010

Abstract

Pore-scale images obtained from a synchrotron-based X-ray computed micro-tomography (µCT) imbibition experiment in sandstone rock were used to conduct Navier–Stokes flow simulations on the connected pathways of water and oil phases. The resulting relative permeability was compared with steady-state Darcy-scale imbibition experiments on 5cm large twin samples from the same outcrop sandstone material. While the relative permeability curves display a large degree of similarity, the endpoint saturations for the µCT data are 10% in saturation units higher than the experimental data. However, the two datasets match well when normalizing to the mobile saturation range. The agreement is particularly good at low water saturations, where the oil is predominantly connected. Apart from different saturation endpoints, in this particular experiment where connected pathway flow dominates, the discrepancies between pore-scale connected pathway flow simulations and Darcy-scale steady-state data are minor overall and have very little impact on fractional flow. The results also indicate that if the pore-scale fluid distributions are available and the amount of disconnected non-wetting phase is low, quasi-static flow simulations may be sufficient to compute relative permeability. When pore-scale fluid distributions are not available, fluid distributions can be obtained from a morphological approach, which approximates capillary-dominated displacement. The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed. The morphological approach does not represent the imbibition process very well and experimental data for the spatial arrangement of the phases are required. Presumably for modeling imbibition relative permeability an approach is needed that captures moving liquid-liquid interfaces, which requires viscous and capillary forces simultaneously.

Highlights

IntroductionFor the description of multiphase flow in porous media on the Darcy scale, commonly the (phenomenological) extension of Darcy’s law to multiphase is employed
For the description of multiphase flow in porous media on the Darcy scale, commonly the extension of Darcy’s law to multiphase is employed
The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed

Summary

Introduction

For the description of multiphase flow in porous media on the Darcy scale, commonly the (phenomenological) extension of Darcy’s law to multiphase is employed. The concept of relative permeability is introduced [21,26] to account for the presence of other immiscible fluid phases [61]. Together with the standard parameters porosity φ, (absolute) permeability K, fluid viscosities μi, and the capillary pressure pc vs saturation Sw function, the relative permeability kr is one of the key parameters to model the flow of multiple phases. In reservoir engineering, where on the field scale viscous forces dominate over capillary forces [36], the relative permeability vs saturation function together with absolute permeability has a large influence on the flux of fluid phases. Relative permeability can largely vary depending on rock type, wettability and other parameters, which can have a major impact on oil recovery by water flooding. Relative permeability is difficult and is experimentally time-consuming to obtain

Methods

Results

Conclusion