MULTIPHASE FLOW MODELING OF CO2 INJECTED INTO DEEP SALINE FRACTURED RESERVOIRS IN KNOX GROUP, BLACK WARRIOR BASIN, ALABAMA
The Knox Group in central Alabama is composed of a thick sequence of dolomite and dolomitic limestone. Laboratory core analysis indicates that porosity is typically 3 to 5% and that matrix permeability is low (~ 0.003-0.005 mD). However, injection tests have demonstrated large injectivity, indicating fractures are the primary source of permeability. Recent analysis of FMI logs has confirmed the existence of abundant open fractures. Two sets of fractures have been identified in the FMI log from a deep test well, and fracture orientation in the Knox Group is consistent with that in surface strata, indicating a similar structural origin. The basic statistical properties of the Knox fracture networks were used to stochastically generate multilayer DFN models.
To determine the viability of CO2storage in fractured Knox carbonate, we have developed multiphase flow models with a new algorithm for characterizing effective fracture permeability (EFP) that includes integration of discrete fracture network (DFN) models. Preliminary results predict significant permeability anisotropy that favors development of a northeast-elongate CO2 plume. The saturation model simulating 1.5 years of injection further predicts significant heterogeneity of CO2 saturation within the plume. The diffusive spreading front of the CO2 plume shows strong viscous fingering effects. Open fractures, moreover, make a significant contribution to plume buoyancy. Post-injection simulation indicates significant lateral spreading of CO2 at the top of the fractured layers. Addional simulations are required to evaluate long-term storage security, and preliminary simulations suggest that leakage through low-permeability upper Knox carbonate is minimal.