Abstract Inversions of earthquake focal mechanisms are among the most accessible and reliable methods for determining crustal stress. However, the use of this method varies widely, and the assumptions that underpin it are often violated, potentially compromising stress estimates. We investigate the consequences of violating the little-studied assumption that the focal mechanisms have diverse orientations. Our approach is to employ data-informed synthetic mechanisms, with nodal plane orientations defined by recent earthquake lineaments in the Midland Basin, western Texas, and rakes consistent with slip in the mapped stress field. Using both the traditional stress inversion method that assumes constant shear stress magnitudes on the causative faults as well as a recently published variable shear stress method, we show that low fault plane diversity can cause maximum horizontal stress ( S Hmax ) orientation and relative principal stress magnitude (faulting regime) estimates to differ markedly from the true values. This problem is compounded for catalogues with even modest amounts of noise (≤15°) or few (e.g. 20) mechanisms. Significantly, traditional approaches for quantifying uncertainty such as the bootstrap can severely underestimate the true uncertainty under these circumstances. To remedy this, we provide simple tools to quantify nodal plane orientation diversity and stress inversion reliability.

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 call 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 the 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 the 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.