Natural fractures in carbonate-rich tight oil reservoirs from the Permian Lucaogou Formation, southern Junggar Basin, NW China: Insights from fluid inclusion microthermometry and isotopic geochemistry

Abstract

Natural fractures within tight reservoirs form preferred pathways for hydrocarbon charge and provide space for hydrocarbon preservation. However, the mechanism that controls the formation of natural fractures in tight reservoirs remains controversial. This study investigates natural fractures within carbonate-rich tight oil reservoirs from the Permian Lucaogou Formation in the Jimsar Sag, southern Junggar Basin. Drill core and image log observations show that fractures in the Lucaogou Formation can be categorized into two types: bedding-parallel fractures and inclined fractures. The carbon and oxygen isotopic compositions of calcite cements in the bedding-parallel fractures range from 0.6‰ to 6.0‰ (δ13CPDB), and from −15.5‰ to −8.9‰ (δ18OPDB), respectively, which are similar to those of the organic-rich host rock. This suggests that the bedding-parallel fractures likely formed in a closed fluid system. Fluid inclusion analyses of the aqueous inclusions in calcite cements from the bedding-parallel fractures record homogenization temperatures of 91.5 °C–130.4 °C, indicating that they formed at the Cretaceous to Cenozoic, during when the Lucaogou Formation reached peak oil generation stage. Therefore, the bedding-parallel fractures were most likely generated by hydrocarbon generation overpressure. The presence of hydrocarbon inclusions in bedding-parallel fracture cements supports natural fracturing by high pore-fluid pressure. The δ13CPDB and δ18OPDB of calcite cements within the inclined fractures vary from 3.6‰ to 9.6‰, and from −11.0‰ to −2.9‰, respectively, which are close to those of the carbonate-rich parent rock. This also supports a closed fluid system scenario. The relatively lower fluid inclusion trapping temperatures (70.5 °C–109.7 °C) suggest that they were likely generated by decrease of confining stress during uplift processes. Therefore, both an increase in pore-fluid pressure and a decrease in confining stress contribute to the formation of natural fractures in the Lucaogou Formation tight oil reservoirs.