RESERVOIR CHARACTERIZATION AND FLUID RECOVERY IN CARBONATE MUDROCKS—THE UNCONVENTIONAL CONVENTIONAL RESERVOIR
Published:January 01, 2017
T. Dawn Jobe, A. Franklin, M. Alsuwaidi, W. Alameri, J.F. SARG, 2017. "RESERVOIR CHARACTERIZATION AND FLUID RECOVERY IN CARBONATE MUDROCKS—THE UNCONVENTIONAL CONVENTIONAL RESERVOIR", Characterization and Modeling of Carbonates–Mountjoy Symposium 1, Alex J. Macneil, Jeff Lonnee, Rachel Wood
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The majority of carbonate reservoir rocks have been developed using conventional development schemes, owing to the presence of macropores that are the product of depositional textures modified by diagenesis. Carbonate reservoir heterogeneity is complex, due to ternary porosity distributions composed of matrix, vugs, and fractures. Recently, matrix-related microporosity has been recognized as an important control on storage capacity and hydraulic conductivity of hydrocarbons. With the advancement of completion technologies for low-permeability reservoirs, quantifying the matrix-related microporosity, understanding pore size and pore throat distributions has become increasingly important. Matrix porosity contribution is often overshadowed by the relative contribution from vugs and fractures, yet it is the matrix pore network that effectively “feeds” the vugs and fractures.
The main focus of this research has been on carbonate reservoir mudrocks that lack macropores and contain pores that are less than a micrometer in size. Examples come from both conventional mudrocks from the Arabian Peninsula and unconventional mudrocks from the Bakken-Three Forks reservoirs of the Williston Basin. These mudrocks have porosities that range from <5% to >20%, and permeabilities that are most commonly ≪1 mD.
Porosity is quantitatively estimated by petrographic image analysis and QEMSCAN® analysis. Estimated porosities are compared with measured porosity from a Core Measurement System (CMS)® 300 automated permeameter. Porosity and pore throat distributions are determined by mercury porosimetry and nitrogen gas adsorption experiments to capture both micropore and nanopore distributions. Results show distinct differences in porosity, permeability, surface area, and tortuosity among different facies. Pore size distributions indicate bimodal pore systems that are in the microporosity to nanoporosity range and that vary across different lithofacies. These variations are related to subtle differences in physical rock properties. Effective fluid flow requires a significant volume of larger micropores to access and connect nanopores.