Estimation of Relative Permeability in Nanoporous Samples and Modeling of Pressure Transient Response in Naturally Fractured Reservoirs

Abstract

Relative permeability and irreducible saturations of organic-rich shale samples from various formations from different maturity windows are estimated by processing the low-pressure nitrogen adsorption-desorption measurements. Using percolation theory, effective medium theory and critical path analysis along with bimodal fractal regime, we estimate relative permeability curves for 100 samples of Bakken, Eagle Ford, Woodford, and Wolfcamp formations. The process also allows estimation of percolation and fractal parameters like coordination number and fractal dimension which facilitate description of the pore network for these shale samples. Transport properties are compared across different windows of maturity. Subsequently, reservoir simulation is used to predict the biphasic production performances of the corresponding formations and correlate predictions with field performance in unconventional reservoirs. Pressure transient analysis (PTA) can describe properties of subsurface natural fractures. Multistencils fast marching (MFM) method provides a reliable way to analyze the effects of natural fractures on the time-varying drainage volume and pressure transient response due to a production/injection well. The method is validated in various heterogeneous reservoirs against the response of equivalent systems generated using the Kappa Saphir commercial software. We study the sensitivities of pressure transients to fracture characteristics, such as fracture length, fracture compressibility, fracture permeability, angle of orientation, and fracture volume fraction in the reservoir. In doing so, we identify diagnostic signatures associated with these fracture characteristics.