Characterization of Critical Fluid, Rock, and Rock-Fluid Properties-Impact on Reservoir Performance of Liquid-rich Shales

Abstract

Abstract Liquid-rich Shale (LRS) reservoirs are economically attractive but operationally challenging. Fluid, rock, and rock-fluid properties are critical for optimal reservoir development and management. Formation heterogeneity, fluid variability, and complexity of rock-fluid properties render fluid flow characterization a challenging task. Additional challenges associated with coring, fluid sampling and analysis include the recovery of quality cores and representative fluid samples, and timely acquisition of high quality data for making critical engineering design decisions. Rock and fluid analyses should be done in the following stages so that the critical data become available in a timely manner for making key decisions: a) ‘Wellsite Analysis’ including mineralogy/total organic content, TOC; b) ‘Quick Look laboratory analysis’ for detailed mineralogy and basic petrophysical properties; c) ‘Fast Track’ geomechanical, geochemical properties and petrophysical analysis on core plugs; and d) ‘Full Suite’ rock-fluid analysis for integrated studies. Low formation permeability, long transients, and contamination with OBM and fracturing fluid make acquisition of representative downhole or early surface fluid samples impractical. An alternative approach is to integrate mud gas analysis with light and heavy end components extracted from full diameter cores in canisters to reconstruct in-situ fluids. The PVT modeling should account for the impact of high capillary pressures encountered in unconventional shale reservoirs for reliable reservoir performance prediction. This paper presents the best practice methodology for characterizing critical rock and fluid properties, their variability and their impact on performance through parametric simulation studies. A sector model was constructed consisting of alternate TOC- and calcite-rich layers with a horizontal well placed in a calcite-rich layer. A network of hydraulic and natural fractures was implemented in the model to study the sensitivities to fluid and rock properties, relative permeability, capillary pressure, and fracture properties. It was found that the critical rock and fluid data impacting the initial rate and ultimate recovery were effective permeability, its anisotropy, its alignment with hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior such as decreased oil bubble point pressure and the resultant viscosity and GOR behavior, interfacial tension (IFT)/capillary pressure, and relative permeability.