Capillary end effect develops in tight gas and shale formations near hydraulic fractures during flow back of the fracturing treatment water and extends into the natural gas production period. In this study, a new multi-phase reservoir flow simulation model is used to understand the role the capillary end effect plays on the removal of the water from the formation and on the gas production. The reservoir model has a matrix pore structure mainly consisting of a network of micro-fractures and cracks under stress. The model simulates water-gas flow in this network with a capillary discontinuity at the hydraulic fracture-matrix interface.
The simulation results show that the capillary end effect cause significant formation damage during the flow back and production period by holding the water volume and saturation near the fracture at higher levels than that based on only the spontaneous imbibition of water. The effect makes water less mobile, or trapped, in the formation during the flow-back and tends to block gas flow during the production. The stress change effects during the production are relatively less important. We showed that the capillary end effect cannot be removed completely but can be reduced significantly by controlling the wellbore flowing pressure and by altering the formation wettability.
Hydraulic fracturing is a well stimulation technique for improved natural gas production from tight gas and shale formations. However, the implementation of the technique brings in new formation damage considerations. During the fracturing treatment, a large volume of water is pumped with proppants into the well. The injected water at high pressure applies the downhole force necessary for the fracture initiation and growth into the formation. Following the treatment, the well is flowed back. Only a small fraction of the injected water can be recovered, however, during the flow-back and natural gas production (Cheng, 2012). A large portion of the water is left behind in the fractures as residual water. Several studies argued that during the treatment forced imbibition of the fracturing water into the water-wet clayey portion of the formation as another reason for the fracturing fluid loss (Bennion and Thomas, 2005; Shaoul et al., 2011, Cheng, 2012; Eveline et al., 2017). The injected water lost to the formation creates a region of high water saturation which may lead to liquid blocking near the fracture during the gas production (Shaoul et al., 2011) and to clay swelling (Scott et al., 2007; Eveline et al., 2017). These studies have previously showed the potential flow impairment mechanisms in tight gas and shale formations and discussed to a certain extent that they may influence a well's performance during production. However, these studies did not consider the existence of capillary end effect (CEE). In ultra-low permeability formations, such as tight gas and shale, the sizes of the pores and cracks contributing to the transport of fluids are significantly reduced. Hence, once the fresh fracturing water invades, the formation experiences large gas-water capillary pressure. Consequently, the two-phase flow dynamics during the flow-back could be controlled by capillary forces. In the presence of strong capillarity, the capillary discontinuity at the fracture-matrix interface will retain the injected water within the formation. This retention could cause high levels of immobile water saturation near the fracture and significantly amplify the liquid blocking in the formation.
