Investigation of dynamic pore pressure in shale gas reservoir during the multi-fracturing and its influence on fault slip

Abstract Casing deformation and micro-seismic event in shale gas reservoir has been of growing interest in the industry, which is attributed to the fault slip induced by multi-fracturing in shale gas wells. It has been widely acknowledged that the variation of pore pressure affects fundamentally the fault slip. However, the currently reported analytical models of pore pressure is not available to specially couple the key effects of shale anisotropy and accumulation of fracturing fluid induced by multi-fracturing. In this work, the characterization approach of fluid conductivity in shale reservoirs near-wellbore during multi-fracturing is established by employing the series-parallel principle. In addition, depending on Hsieh's methods, the comprehensive analytical model of pore pressure variation during multi-fracturing is established by utilizing both the matter conservation law and mechanical mechanism of fluid-solid interaction, fully incorporating the various transmissibility of the matrix, natural fracture, hydraulic fracture and fault zone in shale reservoir. Moreover, the reliability of proposed model is successfully verified through the excellent agreements compared with the numerical approach and field observation. Furthermore, the effects of perforation cluster distance, fracturing stage length, fracturing fluid viscosity and fracturing rate on faults slip are explicitly investigated, by combining the Amontons Law. The consequences demonstrate that the pore pressure variation in shale reservoir induced by hydraulic fracturing is preferentially distributed along the wellbore, fracturing area and fault zone, rather than be uniformly as the sandstone reservoir. Besides, the pore pressure at the repeated fracturing stages remains obviously high, due to the effect of the retention of fracturing fluid. The hydraulic fractures directly communicating with faults, or non-communicating but formation pressure obviously varying, are both able to trigger the fault activation. The pore pressure on fault plane still redistributes from higher pore pressure area to lower pore pressure area after fracturing, rather than stops transmitting at once. It implying that more area of the fault is active and more micro-seismic events occurs after the fracturing pump stopping. “Fewer stages with more clusters”, and the reasonable adjustment of fracturing fluid viscosity can effectively alleviate the extreme distribution of formation pressure, as well reducing the risk of fault slipping.