The Effect of Microporosity on the Fluid Properties in Heterogeneous Formations
Ayaz Mehmani¹, Masa Prodanovic¹, and Adrian P. Sheppard²
¹The University of Texas at Austin, PGE Dept., Austin, TX
²Australian National University, Canberra, Australia
Carbonate rocks are ubiquitous oil and gas reservoirs that have important pore scale features on milimeter scale (vugs, fractures), micron and submicron scale. Furthermore, submicron porosity has a dominant effect on petrophysical properties. A robust method for modeling multiphase flow in rocks dominated by microporosity would thus greatly improve predictions and producibility in carbonate reservoirs.
Pore space characterization on various scales is available, albeit from disparate sources. Computed tomography is widely used for imaging rock cores and sediments with voxel length from a few microns to a few milimeters. Recently, focused ion beam microscopy has been employed to give insight into submicron porosity of carbonate rocks. It would thus be of great interest to utilize the available experimental information from two (and possibly more) length scales in flow modeling.
In order to reduce computational cost, yet capture relevant physics, porous media are modeled as networks of pores and throats (constrictions). We present an algorithm to geometrically match pore throat networks from two separate length scales, that can be extracted directly from 3D images, or be constructed to match the relevant small-scale properties of the pore space. While many multiscale approaches exist, to our knowledge this is the first time network modeling is used on both scales.
AAPG Search and Discovery Article #120034©2012 AAPG Hedberg Conference Fundamental Controls on Flow in Carbonates, Saint-Cyr Sur Mer, Provence, France, July 8-13, 2012