3D geocellular modeling for reservoir characterization of lacustrine turbidite reservoirs: Submember 3 of the third member of the Eocene Shahejie Formation, Dongying depression, Eastern China

3D geocellular modeling is increasingly essential in the petroleum industry; it brings together all petroleum disciplines, and it is commonly used in simulation and production forecast. However, modeling slope and deep-water turbidite reservoirs using conventional modeling methods pose a significant challenge due to the structural complexity and thin-beds associated with these reservoirs. Through the innovative modeling technology of PaleoScan, the reservoirs in Sub member 3 of the third member of the Shahejie Formation are modeled to understand the structural framework. The resulting model is populated with petrophysical properties i.e., porosity and permeability to predict their lateral and vertical distribution within these sandstone reservoirs. The study suggests that the reservoir in the highstand system tract (HST) is characterized by the clinoforms configuration framework. The reservoir is highly faulted mainly in the northern and southeastern parts of the depression. The sedimentary layers are deposited across the slope and downlapping, thinning, and terminating toward to the west. The two isochore surface maps reveal sediment thickness variation and depositional trends within each individual depositional layer. The zones or areas that corresponds to low values on the thickness maps suggest minor uplifts associated with intensive faulting in the Eocene period. These topographical highs played a fundamental role in distributing the sediments delivered to the basin from distant sources. The maps reveal that sediments that filled the basin appear to come from different source points, primarily delivered from the north, southeast, and northeast of the basin with varying depositional trends. The modeled porosity and permeability indicate that the delta fed turbidite reservoirs are characterized by medium to high porosity values of 10–20% and low to medium permeability values of 30-410mD, respectively. The porosity values increase to the southeast and toward the basinwards (west) while permeability varies within the individual sedimentary layers. The distribution of porosity and permeability is not uniform vertically. This suggests the presence of mixed none-reservoir layers with locally and periodically deposited sandstone reservoirs within the stratigraphic during rapid delta progradation. The HST is characterized by six different delta progradation cycles; each phase produced locally deposited lacustrine turbidite sandstones in the basin, which are essential reservoirs in this Formation. The innovative PaleoScan interpretation technology has successfully created a high-resolution 3D reservoir model of this complex geology-such innovative technology is vital to similar complex geology globally.