Wellbore instability in naturally fractured formations: Experimental study and 3D numerical investigation

Abstract

Wellbore instability due to natural fractures is a significant issue impeding drilling operations in shale formations. However, most of the existing literature on wellbore stability analysis focuses on the coupled effects of fluid flow and deformation, and the impact of three-dimensional natural fracture characteristics on wellbore instability is not yet closely examined. This paper carried out a series of experiments to analyze the shale sample's fracture characteristics and shear strength. A fully coupled 3D hydro-mechanical model was then developed using the distinct element method (DEM) to investigate the wellbore instability. Finally, a comprehensive parametric study was performed to analyze the effects of characteristics of fractures (e.g., distribution density, fracture roughness and associated shear strength, dip angle, and seepage time) on wellbore stability under different in-situ stress states. The results show that the shear strength of shale increases with the increase in normal pressure (4 MPa, 6 MPa, and 8 MPa); the shear strength increases by 64.9% when the roughness is 0.325 mm (the largest increase among the three roughness cases). The maximum displacement around the wellbore is 1.3–1.5 times greater under the presence of weak planes than under no weak planes. Fracture roughness poses an important impact on wellbore stability because larger fracture roughness is associated with higher fracture shear strength. As the dip angle of the weak plane increases, the number of yield zones (shear failure) and maximum wellbore displacement increases and then decreases, and the peak occurs at the dip angle of 45°. The seepage time of drilling fluid is positively correlated with the number of yield zones around the wellbore, and the damage rate of drilling fluid to wellbore stability gradually decreases with the seepage time.