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Pore pressures in the Xujiahe gas-bearing formations are highly overpressured in the western Sichuan basin. The abnormally high overpressure and strong tectonic stress cause very high horizontal stresses. The high in-situ stresses, tectonic stress regimes, and tight formations severely impact development and production of the Xujiahe tight sandstone reservoirs. Overpressure generation mechanisms are analyzed based on measured data in several dozen wells in the studied gas fields. It is found that the sonic or seismic transit time can be used to predict pore pressure. Two major reservoirs (Xu2 and Xu4) belong to different fluid compartments with distinct pore pressure gradients. The Xu4 has a much higher pore pressure gradient (20 MPa/km) than the Xu2 (15.6 MPa/km). Measured data from hydraulic fracturing tests and borehole image logs in vertical wells are analyzed. The results show that the minimum horizontal stress gradient in the Xu4 reservoir reaches as high as 24 MPa/km, close to the overburden gradient. The Xu2 reservoir has a slightly lower minimum horizontal stress gradient. The high minimum horizontal stress and high rock strength cause abnormally high formation breakdown pressure gradient (24.8–34 MPa/km). The high breakdown pressure, high propagation pressure, and unfavorable stress regime result in a great difficulty for the reservoir stimulation. One of the major impacts is that hydraulic fracturing operations can only create very short hydraulic fractures, which markedly limits reservoir productivity. Based on field measurements, in-situ stress determination and assessment are given, and a new method for horizontal stress estimation is proposed. Accordingly, reliable prediction of formation breakdown and propagation pressures are proposed, which are more suitable for the tight reservoirs. Recommendations are given for effective development of the tight reservoirs with impacts of high in-situ stresses. Image 1 • Impact and mechanism of in-situ stresses and strong tectonics are studied for hydraulic fracturing in tight sandstone reservoirs. • Overpressure and tectonic stress cause very high horizontal stresses and induce extremely high breakdown pressure. • Pore pressure prediction and horizontal stress estimation methods are proposed. • New methods of formation breakdown and fracture propagation pressures are obtained for tight reservoirs. • Recommendations are given for effective development of the tight and high in-situ stress reservoirs. [ABSTRACT FROM AUTHOR]

The Weirong shale gas field, located within a low-steep structural belt in southern Sichuan Basin, China, is characterized by gentle structural deformation. Production results have shown that inter-well interference, also known as fracture channeling, affects the productivity of shale gas wells by facilitating fluid flow between wells along pre-existing natural fractures. In this study, we used core observational data, scanning electron microscopy, and image logging analysis to determine the type, intensity, occurrence, and genetic mechanism of the natural fractures in the Upper Ordovician Wufeng-Silurian Longmaxi Formation. Attributes such as seismic coherence, AFE (fault-enhanced attribute), dip, and curvature were utilized to predict the macro and meso fault-fractures in the study area. We modeled the micro fault-fractures using the seismic and tracking algorithm to characterize the faults at multiple scales in the Weirong shale gas field, and then completed a comprehensive evaluation of the overall fracture development patterns with respect to the fracture channeling of neighboring shale gas wells. Results indicate that both horizontal and vertical structural fractures have been developed in the shale reservoir of the Wufeng-Longmaxi Formation in the Weirong shale gas field, although the horizontal fractures heavily outnumber the inclined ones. While a few high-conductivity macro and meso fractures display a NE-SW strike, abundant micro-faults have NE-SW and NWW-SEE strikes. Due to the pre-existing basement faults, stress fields and micro-amplitude structure, the NWW-SEE-trending micro fault-fractures are more active than those oriented in the NE-SW direction. Based on field observations, we conclude that regions with well-developed natural fault-fracture networks are more likely to have experienced fracture channeling between or within the platforms of well groups; and the NWW-SEE-trending micro fault-fractures generate more inter-well interference than the NE-SW-trending ones. Predicting the distribution and understanding the origin of the micro fault-fractures make it possible to prevent or mitigate the effects of fracture channeling during the drilling and artificial stimulation of shale gas wells. • Post-stack seismic techniques are used for fracture prediction. • Micro fractures can be accurately characterized by using tracking algorithm. • Natural fault-fracture networks are related to phenomena fracture channeling. • Predicting the micro fractures can prevent the effects of fracture channeling. [ABSTRACT FROM AUTHOR]