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Abstract

The permeability characteristics of natural fracture systems are crucial to the production potential of shale gas wells. To investigate the permeability behavior of a regional fault that is located within the Wufeng Formation, China, the gas permeability of shale samples with natural micro-fractures was measured at different confining pressures and complemented with helium pycnometry for porosity, computed micro-tomographic (µCT) imaging, and a comparison with well testing data. The cores originated from a shale gas well (HD-1) drilled at the Huayingshan anticline in the eastern Sichuan Basin. The measured Klinkenberg permeabilities are in the range between 0.059 and 5.9 mD, which roughly agrees with the permeability of the regional fault (0.96 mD) as estimated from well HD-1 productivity data. An extrapolation of the measured permeability to reservoir pressures in combination with the µCT images shows that the stress sensitivity of the permeability is closely correlated to the micro-fracture distribution and orientation. Here, the permeability of the samples in which the micro-fractures are predominantly oriented along the flow direction is the least stress sensitive. This implies that tectonic zones with a large fluid potential gradient can define favorable areas for shale gas exploitation, potentially even without requirements for hydraulic fracture treatments.