Relative permeability of tight hydrocarbon systems: An experimental study

Abstract

Relative permeability is notoriously difficult to measure in the laboratory for low-permeability rocks with permeability values in the nanodarcy/microdarcy range. The objectives of this work are to 1) implement a series of laboratory methods for relative permeability estimation in tight hydrocarbon formations and 2) examine the impact of fluid saturation and operational (e.g. pore pressure, differential pressure) controls on relative permeability. Seven tight siltstone/sandstone and organic/clay-rich core plugs, covering a broad range of helium porosity (2.9–13.8%) and slip-corrected gas (N2, CH4) permeability values (1.5·10−5–1.6·10−1 md), were analyzed in this study. Two direct methods for measuring gas/liquid (CH4,N2/oil) relative permeability data are investigated including a modified version of the Dacy method and the “gas breakthrough” technique, tailored to high- (˃0.001 md) and low-permeability rocks (<0.001 md), respectively. The non-steady-state method under constant flow rate is used for evaluating liquid/liquid (oil/water) relative permeability for a Montney core plug sample. Using a unipore diffusion model, the gas/liquid (CH4/oil) effective diffusion/dispersion coefficient is evaluated for a Duvernay core plug sample. The relative permeability values measured on fully/partially oil-saturated core plug samples vary between 0.006 and 0.9, depending on methodology, oil saturation (30–75%), pore pressure (1.3–6.4 MPa), effective stress (3.3–19.4 MPa), differential pressure (0.5–3.1 MPa) and hysteresis path. The systematic experiments conducted herein extend the available experimental dataset and are of significant importance for constraining rate-transient analysis (RTA) models and numerical simulations used to evaluate primary and enhanced oil recovery in tight hydrocarbon systems.