Numerical Investigation of Water Blockage in Secondary Fractures and Apparent Permeability Modeling in Shale Gas Production

During the hydraulic fracturing process, the fracturing fluid may cause water blockage, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The fluid inside the fractures could also get squeezed out upon fracture closure. 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 blockage 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 network (DFN) model is upscaled into equivalent continuum dual-porosity dual-permeability (DPDK) model by analytical techniques. A realistic DFN configuration is examined to simulate the potential scenarios of water blocking. An apparent permeability (K_app) model that accounts for contributions of Knudsen diffusion, slip flow and surface pore roughness is introduced. 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.

Fracture closure and the resulting water blockage would impact the gas production and water recovery, particularly if the near-well fractures are disconnected. 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, which is contrary to some conclusions in previous research where K_app modeling and disconnected fractures are ignored. The impacts of shut-in duration and matrix multiphase flow functions are systematically studied. 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, where previous studies have reported no observable increase in gas production when secondary fracture closure was not considered.

This work presents a set of detailed simulation studies to examine the scenarios or conditions that may be responsible for water blockage, particularly in the presence of disconnected secondary fractures. A novel, yet practical, scheme is implemented to couple stress-dependent matrix apparent permeability and fluid flow, as well as to model pressure-dependent fracture closure. The 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.