Diagenesis, reservoir-quality, and oil-bearing heterogeneity of the Eocene deep-lacustrine mudstone in the Qibei Sub-sag, Bohai Bay Basin, China

Lacustrine organic-rich Eocene mudstones are well developed and demonstrates significant exploration potential for shale oil in the Qibei Sub-sag, Bohai Bay Basin, China. However, their oil content displays strong heterogeneity, which poses challenges for effective exploration and development. Diagenesis implicates compaction, cementation, dissolution/re-precipitation processes that raises critical questions regarding reservoir quality and oil-bearing heterogeneity.

Integrated high‐resolution petrologic analysis, organic geochemistry, and pore throat structure characterization provide a powerful approach to investigate the diagenesis, reservoir and oil-bearing characteristics. The 50 samples were collected from the 111.39-m-thick Eocene the first Sub-member of the third Member of the Shahejie Formation lacustrine oil-prone source rock succession penetrated by the two wells in the Qibei Sub-sag. Six typical lithofacies were identified: laminated medium-grained calcareous shale, laminated fine-grained mixed shale, thin-bedded fine-grained mixed mudstone, thin-bedded medium-grained mixed mudstone, massive medium-grained mixed mudstone, and thin-bedded coarse-grained felsic mudstone.

The micritic calcite laminae formed during the sedimentary stage underwent recrystallization during the early to middle diagenetic stages, transforming into granular sparry calcite. Potassium feldspar dissolution and clay mineral transformation resulted in the formation of authigenic albite and quartz. These diagenetic processes promoted the development and preservation of intercrystalline/interparticle pores. As a result, the laminated medium-grained calcareous and laminated fine-grained mixed shale reservoirs exhibit superior reservoir properties, primarily characterized by interparticle pores, intercrystalline pores, clay mineral-associated pores, and bedding fractures. With a median pore throat diameter of 11.6 nm and an average porosity of 6.53%, these reservoirs are classified as Type I. The thin-bedded fine-grained mixed shale primarily develops clay mineral-associated pores and interparticle pores, with some bedding fractures. Its median pore throat diameter is 9.2 nm, and the average porosity is 5.56%, classifying it as a Type II reservoir. The thin-bedded medium-grained mixed and massive medium-grained mixed mudstones mainly develop interparticle pores and clay mineral-associated pores. These have a median pore throat diameter of 12.6 nm and an average porosity of 4.3%, classifying them as Type III reservoirs. In felsic mudstone, calcite cementation significantly reduced porosity during the early diagenetic stage. This results in the poorest porosity development in the thin-beded coarse-grained felsic mudstone, which has a median pore throat diameter of 15.9 nm and an average porosity of 3.26%, classifying it as Type IV reservoir.

The laminated medium-grained calcareous shale, laminated fine-grained mixed shale, and thin-bedded fine-grained mixed mudstone exhibit relatively high oil content and OSI values. The average oil content values are 2.48 mg/g, 2.64 mg/g, and 2.30 mg/g, respectively, and the average OSI values are 144 mg HC/g TOC, 163 mg HC/g TOC, and 168 mg HC/g TOC. These lithofacies are favorable for shale oil exploration and development. We suggest that addressing the challenges of mudstone diagenesis will significantly improve understanding and prediction of reservoir quality and oil-bearing heterogeneity in unconventional shale oil plays.