Fracture/fault reactivation determination and carbon storage stability analysis of CO2 injection in shale reservoirs after fracturing

Abstract CO2 geological storage and enhanced oil recovery (CO2-EOR) are key pathways for the low-carbon energy transition. In fractured shale reservoirs, however, injection-induced pore-pressure buildup and stress redistribution may reduce fault stability and threaten storage safety. To quantitatively evaluate fault stability, this study develops a three-dimensional numerical model including injection wells, hydraulic fractures, and high-angle faults, incorporating CO2 adsorption–desorption effects. Fault slip tendency (ST) is adopted as the activation criterion to characterize fault-stability evolution. Sensitivity analyses are conducted for key engineering parameters, including injection rate, cumulative injection volume, injection location, fault–well distance, and fracture half-length. Grey relational analysis is used to identify the main controlling factors. Results demonstrate a pronounced nonlinear response of fault stability to injection parameters. Under the investigated scenarios, the maximum fault slip tendency varies from 0.35 to 0.91, and a warning threshold of ST = 0.8 is used to identify potential fault activation risk. Specifically, increasing injection rate from 3,000 to 12,000 m3/d raises the maximum ST from 0.60 to 0.91, while bottom injection yields a maximum ST of 0.81, higher than top injection (0.52) and middle injection (0.35). Increasing fracture half-length from 90 to 180 m raises the maximum ST from 0.45 to 0.81. Grey relational analysis shows that the relative influence of the investigated parameters is ranked as cumulative injection volume injection location fracture half-length injection rate fault–well distance.