Overcoming wellbore drilling instability in fractured-rock formations always presents one of the major challenges to drilling engineers. Due to different fluid-diffusion rates and compressibility degrees between the rock’s matrix and fracture network, there are two distinct pore-pressure fields and subsequently different effective stresses developed in a saturated fractured formation. It is recognized that wellbore instabilities such as collapses are caused by excessive effective stress concentrations at or near the borehole wall, and mud losses are due to fracturing the rock formation. Because both the mud/rock fluid-pressure differential and fractures’ deformation modify the effective stresses in the wellbore wall, such intricate responses require a wellbore solution that accounts for the fracture network, intact rock matrix mechanics, and the balance of drilling mud density. In this work, the effects on real-time collapse and fracture gradients that dictate the safe mud weight window are evaluated analytically, incorporating the effects of natural fracture network via a simulated field case. Analyses reveal that neglecting the naturally fractured nature of the formation falls short in simulating the wellbore instability since it predicted a narrower mud weight window for the drilling operation.

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