Conference review: Wallace E. Pratt memorial conference on future petroleum provinces of the world 2–5 December, 1984, Phoenix, Arizona, USA

Abstract

Natural fractures have long been considered important factors in the production of gas from shale reservoirs because they can connect pore spaces and enlarge transport channels, thereby influencing the migration, accumulation and preservation of shale gas. Industrial-level shale gas production has been initiated in the lower Silurian Longmaxi Formation in northern Guizhou, South China. However, it is important to quantitatively predict the distribution of natural fractures in the lower Silurian shale reservoirs to locate additional ‘sweet spots’ in northern Guizhou. In this study, data obtained from outcrops, cores, thin sections, field-emission scanning electron microscope (FE-SEM) images and X-ray diffraction (XRD) were used to determine the developmental characteristics and controlling factors of these fractures. Correlation analysis indicated that the mechanical parameters of the Longmaxi shale are mainly related to the total organic carbon (TOC), quartz, clay, calcite and dolomite contents. The spatial variations in the mechanical parameters of the Longmaxi shale were determined based on the spatial variations in the TOC and mineral contents. Then, a heterogeneous geomechanical model of the study area was established based on interpretations of the fault systems derived from seismic data and acoustic emission (AE) experiments performed on samples of the relevant rocks. The paleotectonic stress fields during the Yanshanian period were obtained using the finite element method (FEM). Finally, a fracture density calculation model was established to analyze the quantitative development of fractures, and the effects of faults and mechanical parameters on the development of fractures were determined. The results suggest that the main developmental period of tectonic fractures in the Longmaxi Formation was the Early Yanshanian period. During this time, the horizontal principal stress conditions were dominated by a SE-NW-trending (135–315°) compressional stress field, and the Longmaxi Formation experienced a maximum tectonic stress of 110–120 MPa. This simulated paleotectonic stress field was mainly controlled by faults and the contents of TOC, quartz, clay, calcite and dolomite; at different positions along the same fault, the degree of fracture development varies significantly. Overall, the distribution of fractures in the Longmaxi Formation can be used to optimize well deployment and provides a basis for the future exploration of shale gas.