Quantifying the Effect of Microporosity on Fluid Flow in Carbonate Reservoirs

Abstract

Understanding the pore system and petrophysical properties of subsurface reservoir rocks is vital for accurate prediction of fluid flow behaviour and therefore hydrocarbon recovery. Predicting some properties of carbonates is a particularly complex task as their pore systems are inherently multi-scalar, often incorporating four relevant orders of magnitude of pore size variation. Perhaps the least understood type of porosity within carbonates is microporosity, where pores are >10μm in diameter. Microporosity has many origins, but that which is formed between micrite crystal faces, known as ‘chalky’ microporosity, can constitute a significant percentage of the total porosity and potential storage capacity of some of the largest known reservoirs. However, few studies have attempted to quantify the contribution of microporosity to multiphase flow and as such, resultant petrophysical properties are not routinely attributed when assessing reservoir quality. Additionally, wetting properties of microporosity are poorly understood, but are also expected to have a large impact on the rock flow properties. We have developed a flexible, object-based rock reconstruction methodology to enable the modelling of fluid flow in heterogeneous, microporous carbonates. The reconstruction reproduces realistic models of micritic fabrics as observable from SEM analysis in order to accurately represent the pore space properties relevant to fluid flow. Multiphase flow simulations performed on extracted pore networks are used to understand the flow properties of different types of microporous fabrics. These models also allow investigation of the relative roles of micropores and macropores, and their distributions, so enabling quantification of geologically-controlled ‘tipping points’ in fluid flow characteristics, and the relative influence of microporosity, macroporosity and their interaction on macro-scale fluid flow. Further, consideration of different wettability distributions within the models, enables these additional effects to be quantified. Such models and multiphase fluid flow simulations will ultimately allow full quantification of how, and under what conditions, micropores contribute to flow under different porosity scenarios, thus leading to a more accurate understanding of the petrophysical properties of micropores.

AAPG Datapages/Search and Discovery Article #90189 © 2014 AAPG Annual Convention and Exhibition, Houston, Texas, USA, April 6–9, 2014