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Characteristics and Origin of Tight Oil Reservoir within the Middle Permian Lucaogou Formation of the Junggar Basin, NW China


The middle Permian Lucaogou Formation in the Jimusaer sag of the southeastern Junggar Basin, NW China, was the site of a recent discovery of a giant tight oil reservoir hosted by lacustrine mixed dolomitic–clastic rocks. Here, we improve our understanding of this tight oil reservoir by presenting the results of a preliminarily investigation into the basic characteristics and origin of this reservoir using field, petrological and geochemical data. Field and well core observations indicate that the Lucaogou Formation is a sequence of mixed carbonate (mainly dolomites), terrigenous clastic (mainly feldspars) and tuff sediments that were deposited in a highly saline environment. The formation is divided into upper and lower cycles based on lithological variations between coarse- and fine-grained rocks; in particular, dolomites and siltstones are interbedded with organic-rich mudstones in the lower part of each cycle, whereas the upper part of each cycle contains few dolomites and siltstones. Tight oil accumulations are generally present in the lower part of each cycle, and dolomites and dolomite-bearing rocks are the main reservoir rocks in these cycles, including sandy dolomite, dolarenite, dolomicrite, and a few dolomitic siltstones. Optical microscope, back scattered electron, and scanning electron microscope imaging indicate that the main oil reservoir spaces are secondary pores. Furthermore, samples with secondary pores which are characterized by low stable carbon and oxygen isotopic values usually developed diagenetic carbonates. Meanwhile, stable carbon and oxygen isotopic values show strong negative correlation with reservoir TOC which indicates that the formation of diagenetic carbonates and secondary pores are directly related to organic fluids. Diagenetic carbonates obviously contributed little to secondary pores. Extensive development of tiny quartz, authigenic albite and illite suggests that quartz-feldspathic tuff and feldspar are more likely to be the key of secondary pores. The negative correlation of stable carbon/oxygen isotopes with reservoir TOC suggest that diagenetic carbonates and the dissolution were formed by organic fluids. Our study suggests that the dissolution of aluminosilicate minerals by organic fluids contributes far more to secondary pores than carbonates, which, on the contrary, act as the records of fluid-rock interaction in carbonate-rich reservoirs.