3D Geomechanical Modeling and Quantitative Prediction of Tectonic Fractures in Unconventional Reservoirs

Reservoirs where tectonic fractures significantly impact fluid flow are widespread. The development and distribution of such fractures are controlled by mechanical parameters and paleotectonic stress fields. Industrial shale gas production has been achieved in the lower Cambrian Niutitang Formation of northern Guizhou, South China. This study utilizes outcrop, core, thin section, and field-emission scanning electron microscope data from this region to characterize tectonic fracture development. Natural fracture, fault, and fold strikes were used to determine the principal paleostress directions; acoustic emission experiments provided paleostress magnitudes. The middle–late Yanshanian paleotectonic stress fields were subsequently modeled via finite element methods. A fracture density calculation model was established to quantify fracture development and assess the influence of faulting, folding, and mechanical parameter variations. The simulated paleostress fields were governed primarily by mechanical parameters (reflecting paleosedimentary environments) and faults. Different faults exert varying degrees of control on fracture density, which also significantly differs along a single fault’s length. Notably, N–S-trending faults exhibit weaker control, whereas central faults demonstrate a more significant influence.