Numerical investigation of water retention in secondary fractures and apparent permeability modeling in shale gas production

During the hydraulic fracturing process, the fracturing fluid may cause water retention, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The circumstances and detailed mechanisms associated with this phenomenon are still poorly understood. In this work, a coupling scheme for incorporating a pressure-dependent apparent permeability model in reservoir simulation is implemented. The numerical models are subsequently used to investigate the impacts of water retention and apparent permeability modeling on gas production and water flowback. A high-resolution 3D reservoir model is constructed based on the field data obtained from the Horn River shale gas reservoir. Stochastic 3D discrete fracture netsork (DFN) model is upscaled into equivalent continuum dualporosity dual-permeability (DPDK) model by analytical techniques. An apparent permeability (K-app) model is employed to model transport mechanisms in nano-sized pore systems. In order to capture the pressure dependency, a novel coupling scheme is developed to facilitate the updating of K-app and effective stress after a certain designated time interval. In addition, a novel method involving rock-type indicators is introduced to represent the open and closed states of secondary fractures, facilitating the modeling of stress-dependent closure of the secondary fracture system. Two secondary fracture closure behaviors (i.e., abrupt closure and gradual closure) are considered in our study. The results indicate that fracture closure would affect the gas production and water recovery, particularly if the near-well fractures are disconnected; the effect would be further exaggerated for a denser fracture network; fracture closure would also affect the matrix water retention near the well. Neglecting the effects of K-app could essentially overestimate the contribution of hydraulic fracture for a certain observed gas production. The existence of secondary fractures could also enhance water loss during flowback. It is concluded that gas and water production would increase if less water is imbibed into the matrix during the shut-in period in the presence of disconnected secondary fractures. It is also observed that a shorter shut-in period may be beneficial to both water and gas recovery. This work presents a novel, yet practical, scheme for coupling stress-dependent matrix apparent permeability and fluid flow, as well as modeling pressure-dependent fracture closure. This modeling scheme can be readily integrated in most commercial reservoir simulation packages. The results have revealed several potential scenarios of water loss, along with the associated implications on optimal operational strategies and estimation of stimulated reservoir volume.