Characterization of fracture formation in organic-rich shales - An experimental and real time study of the Permian Lucaogou Formation, Junggar Basin, northwestern China. (September 2019) - Wu, Songtao; Zhai, Xiufen; Yang, Zhi; Bale, Hrishikesh; Hong, Youli; Cui, Jingwei; Pan, Songqi; Lin, Senhu
Abstract: Volume fracturing in horizontal wells represents a principal technology in the effective economic development of unconventional shale oil and gas reservoirs. However, the number of intervals that were effectively fractured by this technology only account for 20%–50% of the total designed sections. Fracture development characteristics and the factors controlling artificial fracture growth in organic-rich shale require detailed evaluation; this cannot be accomplished using microseismic monitoring technology or well-log interpretation. In this paper, formation processes of micro- and nano-scale fractures in the organic-rich shales of the Lucaogou Formation, Jimusaer Sag, Junggar Basin, northwestern China, were presented. The study focused on the application of in situ, nano-scale CT imaging technology, in combination with rock mechanics analysis. Results allowed the visualization of fracture growth in the shale reservoirs, and revealed the influence of organic matter, mineral composition, and pore structure on the formation and distribution of artificial fractures. A three-dimensional dynamic growth model of micro- and nano-scale fractures in organic-rich shale was established. Data revealed that the Lucaogou Formation shale contained dolomite and illite intragranular pores, with a low abundance of organic pores; pore size ranged between 200 nm and 2 μm. Micro- and nano-size fractures were observed. The development of artificial fractures was positively correlated with the loading stress. The initiation stress of new generated fractures was 475 mN, which could break up dolomite, albite, K-feldspar, and the original pore system as well. The original pore system was generally conducive to fracture extension and expansion. As loading stress increased from 50 mN to 515 mN, the sample extension increased from 2 μm to 14 μm, and artificial fracture width increased from 0.3 μm to 10 μm. The total porosity increased from 5.45% to 8.35%, and volume growth rate reached 53.2%. These findings provide valuable insights into the study of fracture growth in organic-rich shales, and have implications for the design of hydro-fracturing in organic-rich shales. Highlights: 3D real-time fracturing growth process with high resolution in shales is characterized. Relationship among new fractures and pore structure & mineralogy are quantitatively evaluated, as well as fracture sizes. Provide reference for geomechanics research and fracturing in organic-rich shales.