Relative permeabilities from simulation in 3D rock models and equivalent pore networks: critical review and way forward

摘要

In the last 15 years,great progress has been achieved in the area of digital rock technology in the domain of 3D rock model generation using a range of techniques: sedimentation modeling,statistical methods and micro-CT imaging.In the context of sandstones,singlephase prediction from these 3D models or from the equivalent pore networks has become possible for static and,in some cases,for flow petrophysical properties.Nevertheless, according to Sorbie and Skauge [1],two-phase flow properties such as relative permeabilities cannot be predicted neither from the equivalent pore networks nor from the 3D models: in the first case,the input choices one has to make throughout the whole prediction workflow would greatly outnumber the actual system parameters;in the second, whilst the number of input parameters still remains too high,no technique is mature enough to produce calculations”that can be compared meaningfully with experiment”.In this work we extend the observations of Sorbie and Skauge by actually simulating twophase flow properties with a number of state-of-the-art pore network models and one Lattice-Boltzmann simulator.We begin the study by showing how the network extraction process,and not the distribution of the fluids in the pore network,might be at the origin of some recently published counterintuitive results on relative permeabilities,obtained by means of pore network simulation by another group.We then continue showing that the current physics embedded in network models,and the latest refinements to it,are less a concern than other issues such as rock representation and wettability characterisation.We conclude by comparing results from direct two-phase flow simulation in a micro-CT image and in the network model extracted from that image to focus on the issues that need to be addressed to establish these techniques as industry-ready tools.