Pore fluid is blocking due to Micro-Nano pore size. Smaller pore size may cause higher capillary pressure (HCP), and increase the fluid saturation at the rock matrix near the fracture surface, thus reducing the gas relative permeability on a big scale;
Pore size reduction due to the high clay content, especially for the swelling clay mineral such as Smectite and easy mobilization or pore blocking mineral such as Illite.
The unconventional resources from ultra-deep tight gas reservoir have received significant attention in the past decade. During hydraulic fracturing, high hydraulic fracturing fluid (HFF) invaded zone near the fracture face may reduce gas relative permeability significantly and impede gas production. The sources of this damage can be the high capillary pressure (HCP) and the presence of water-sensitive clays (PWC). For tight rock, it is usually infeasible to identify the primary damage mechanism using traditional steady-state measurement method due to long measurement time and gauge accuracy. In this paper, we present a new experimental approach to identify the primary mechanism of the fracture face damage (FFD) through the application of the pressure transmission method and pressure decay method. Both rock matrix and naturally fractured cores (depth 18,000 ft, Tarim field China) were tested. Results showed that the fluid-block due to HCP is the primary damage mechanism for the tight sandstone. And the damage degree of the rock matrix core is higher than that of the naturally fractured core. The proposed procedures can be applied to identify the FFD mechanism of other tight and shale formation and provide insightful fundamental data for HFF optimization.