After hydraulic fracture, the brittleness of shale rocks has led to a network of fractures with different scales and orientations. So far, the flow characteristic investigations have been mostly focused on the matrix (nanoscale) and the macrofractures (wider than millimeter scale) with proppants. Between the nano- and macroscales, those microscale fractures that could not be artificially propped were not studied adequately, although they are essential for gas flow due to the extremely low permeability of the original matrix. To simulate the hydraulic-induced microfractures in the laboratory, we have successfully established a new method on the basis of the Brazilian test to produce microscale fractures in cores. X-ray microtomography exhibited the morphology and aperture scale (110  μm) of the inner fractures. The variety of the fractures morphology was consistent with the previous results of the large-scale hydraulic experiments. The microfractures (aperture 13  μm) enhanced the core permeability by 2–6 orders of magnitude. We found that the pressure-dependent permeability could be expressed by power and exponential functions, whereas the porosity was not applicable to be included in the function. Except for mechanical properties, the fracture permeability and its pressure dependency were intensely influenced by the fracture aperture, tortuosity, and roughness. Furthermore, we suggested that the greater the proportion of natural fractures in the fracture network, the greater the permeability decline with the pressure increase. This knowledge would be essential in practice to estimate the production and to optimize the hydraulic fractures.

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