Coupled Multiphase Flow and Reactive Transport Effects on Hydraulic Fracture Interference during CO 2 -EOR and Storage in Unconventional Reservoirs

Unconventional reservoirs such as the Bakken Formation represent promising targets for combined enhanced oil recovery (EOR) and CO 2 storage. However, their ultralow permeability, complex lithology, and multiwell developments with overlapping hydraulic fractures (HFO) create significant challenges for predicting CO 2 utilization efficiency and long-term storage security. In CO 2 Huff-n-Puff (HnP) operations, poor conformance management often leads to early CO 2 breakthroughs, causing injected CO 2 to promptly migrate to adjacent wells without effectively contacting the designated HnP well. In addition, CO 2 injection and soaking can substantially alter the physical properties of reservoir rocks. These effects strongly influence pore-scale properties, brine chemistry, fluid flow, and mineralogical composition, especially within the heterogeneous mineral framework of the Bakken Formation. Conventional HnP models often simplify fracture connectivity and neglect geochemical impacts, leading to over- or underestimation of recovery and storage performance. This study addresses these gaps by presenting a coupled modeling framework that integrates 3D geological modeling, compositional multiphase flow, and reactive transport processes to assess CO 2 Huff-n-Puff (HnP) efficiency under realistic fracture interference conditions. A multiwell pad (MWP) model was history-matched and used to examine operational strategies, including injection rates, offset well configurations, and fracture connectivity. In parallel, Henry’s law for CO 2 solubility was coupled with aqueous and mineral reactions, allowing explicit simulation of pH changes, calcite dissolution, and permeability evolution during injection. The thermodynamic behavior of brine–CO 2 systems was represented using the Pitzer ion-interaction model, enabling an accurate prediction of ionic strength effects on brine chemistry. Permeability changes were dynamically updated through porosity variations using the Kozeny–Carman relationship, linking geochemical alterations with flow properties under reservoir conditions. The results show that hydraulic fracture overlap (HFO) and interference redistribute pressure and gas flow, enhancing oil recovery in offset (child) wells but reducing the recovery from the designated HnP well. Offset-well closure under both high and low injection rates increases average reservoir pressure, promotes CO 2 dissolution in oil, and improves storage efficiency through dissolved trapping mechanisms, even though open wells allow greater cumulative injection. Moreover, the simulations reveal that CO 2 solubility and geochemical reactions substantially reshape recovery and storage dynamics. Dissolution into brine reduced gas mobility and improved storage efficiency by up to 3.7%, with 6.4% of injected CO 2 trapped in the aqueous phase, though at the expense of oil recovery due to reduced CO 2 –oil contact. Geochemical reactions further demonstrated that mineral buffering by calcite stabilized pH near 5, mitigating severe acidification observed under ionization-only conditions. Mineral dissolution enhanced porosity and permeability, increasing injectivity, and HnP well production. However, under high fracture connectivity, these improvements accelerated CO 2 migration, reducing storage efficiency despite larger injection volumes and higher oil recovery. By explicitly coupling fracture interference dynamics with reactive transport, this study provides a more realistic assessment of CO 2 utilization and long-term storage efficiency in tight reservoirs. These findings provide practical insights for optimizing CO 2 -EOR operations and storage strategies in fractured unconventional systems.