We introduce an analytical workflow for determining relative permeability behavior of two-phase matrix flow within low permeability samples using mercury injection capillary pressure (MICP) drainage-imbibition measurements. Low permeability samples often experience wettability alterations during core cleaning and require extensive time to reach equilibrium conditions, which challenges traditional core flood measurements using reservoir fluids.
Mercury is advantageous as it effectively describes the non-wetting phase connectivity and trapping behavior defined by the pore geometry, regardless of wettability alterations. Sample compressibility occurring during measurement is used to quantify stress sensitivities and the subsequent reduction in porosity and permeability so that extracted values can be representative of reservoir stressed conditions. The MICP drainage-imbibition measurements utilize the compressibility, capillary pressure, and pore geometry concepts to provide Corey power-law wetting and non-wetting phase exponents (nw, nnw) and residual saturation (Sw, Snw) values. The relatively short measurement time allows for high frequency sampling within intervals of interest to determine relative permeability behavior at appropriate vertical resolution.
Data was acquired on samples from produced intervals within the 3rd Bone Spring Sand and Wolfcamp formations across four Delaware Basin wells. These producing wells observed water cuts ranging from 25% to 82%. Core measurement data are applied via petrophysical framework and engineering equations of state (EOS) to model fractional flow at surface for comparison to observed production. The core-calibrated fractional flow models closely match produced water volumes, demonstrating that this methodology can be applied with predictive capabilities. The free fluid saturation (1-Sor-Swir) described by the relative permeability curves indicate only a small fraction of the total porosity is capable of two-phase flow, which suggests that relatively small saturation changes can result in drastic changes in fluid phase mobility. This is reflected in the very steep slope of the fractional flow at surface curve as a function of water saturation.
Relative permeability describes the dimensionless reduction of flow capacity for a fluid phase during multi-phase flow conditions. The understanding of relative permeability behavior is essential for formation evaluation and reservoir engineering objectives. Direct measurement of relative permeability involves flowing reservoir fluids through a core sample, under steady-state or unsteady-state conditions (Honarpour & Mahmood, 1988). Low permeability samples often experience wettability alterations during core cleaning and require extensive time to reach equilibrium conditions, which challenge traditional measurements (Alvarez & Schechter, 2016).