Quantitative Recovery of Marine Shale Porosity Evolution Considering Diagenesis, Pore Pressure, and Hydrocarbon Generation

Summary Reservoir properties and their evolutionary history are of paramount importance for elucidating the formation mechanisms of oil and gas reservoirs and for the selection of prospective exploration areas. However, such investigations remain relatively limited within the realm of shale reservoir research, particularly concerning the quantitative evolution of shale porosity. In this study, we incorporate shale-specific initial porosity and organic matter (OM) pore development models into the conventional backstripping method. A case study of the Longmaxi Formation shale in the Luzhou block was conducted, using total organic carbon (TOC) analysis, X-ray diffraction (XRD), porosity measurements, large-area scanning electron microscopy (Maps-SEM), wide-field scanning electron microscopy (WSEM) coupled with energy-dispersive X-ray spectroscopy (EDS), quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN), and basin modeling. These methods were used to elucidate the pressure evolution, diagenetic processes, and their intensity within the deep Longmaxi Formation shale reservoir of the Sichuan Basin. Based on these findings, a quantitative shale porosity restoration model was developed, explicitly accounting for pore pressure, diagenetic alterations, and OM maturation. The results reveal the following: (1) Longmaxi Formation shale can be divided into siliceous shale, argillaceous shale, and mixed shale. The pores in all three types of shale are mainly OM pores. Inorganic pores are mainly intergranular pores and intergranular fractures, with a low proportion of dissolution pores. The pore composition varies among different shale lithofacies. (2) Differences in the intensity of diagenesis are the cause of differences in pore type composition among different shale lithofacies. Furthermore, compaction is the main factor leading to the decrease in porosity of Longmaxi Formation shale, while OM hydrocarbon generation is the main reason for the increase in porosity. (3) The evolution of porosity in the deep Longmaxi Formation shale can be divided into four stages: During the early diagenetic stage, porosity significantly decreases due to compaction and cementation. In the middle diagenetic stage, vertical effective pressure initially increases and then decreases, while porosity fluctuates significantly due to hydrocarbon generation from OM, reaching a minimum in the Late Triassic (approximately 207 Ma). In the late diagenetic stage, the influence of OM hydrocarbon generation results in a gradual increase in porosity, which subsequently decreases again due to recompaction during the stratigraphic uplift stage. This research can provide insights into the accumulation process and favorable area prediction of deep shale gas.