Natural fracture density controls productivity in shale reservoirs

Abstract

Shale reservoirs host ubiquitous multi-scale natural fractures created by factors such as pore pressure build-up after petroleum generation and palaeo crustal stress changes during tectonic episodes. Natural fractures are among postulated drivers of stimulated shale well productivity and related variability. Quantifying the aforementioned role and optimizing recovery calls for litho-structural assessments. In this interdisciplinary study, natural fracture density (fractures per unit length) for North and South American shales (Marcellus, Eagle Ford, Haynesville, Barnett, Fayetteville and Vaca Muerta) was estimated from published observations of outcrops, cores and borehole images. Associated production for latest horizontal wells, drilled in the most productive locations (sweet spots), was normalized by lateral length and reservoir thickness. It was found to correlate positively with density of small-scale natural fractures. Durations of transient linear flow, diagnosed from production data, were play-specific, negatively correlated with small-scale natural fracture density and led to realization of picodarcy matrix permeability. Conversely, large-scale (tectonic) fractures limit stimulation efficiency and pose environmental/induced seismicity risks. Therefore, stimulation-driven reactivation of small-scale fractures facilitates drainage and enhances well productivity. Relatedly, reservoir flow regimes and production decline curves are intricately controlled by interplay of natural fracture density and matrix permeability. Variability of these parameters calls for acreage-tailored stimulations.