Prediction of petrophysical classes and reservoir beds through microfacies and pore types characterization, Tahe Ordovician naturally fractured vuggy carbonates

Carbonates commonly present a stacking-pattern architecture determined by the depositional processes despite the diagenetic modifications. This study integrates spectral cyclostratigraphy and petrophysical analysis to locate prolific reservoir beds to optimize reservoir development. It involves subdividing the reservoir succession into different hierarchical units to understand the variation of microfacies and pore-structure types. It proceeds by determining the variation-trends and discontinuity surfaces (chronostratigraphic and lithostratigraphic boundaries) by conjointly interpreting the prediction error filter analysis (PEFA) and integrated PEFA (INPEFA) and synthetic seismic trace and seismogram. We define the rock texture types (microfacies) through self-consistent approximation based on the INPEFA log while considering the variation of depositional sequence and grain size, core/thin-section petrography, and borehole electrical image interpretation. We establish lithology-depth and petrophysical classes-depth profiles using largely well-log data and propose new petrophysical classes for naturally fractured vuggy reservoirs. We predict porosity and permeability from the distribution of high-frequency cycles and lithofacies while considering the implications of diagenesis. The results show that the depositional processes and diagenesis largely control the quality of the reservoir beds in response to the relative sea-level variations. The reservoir beds comprise the reservoir units with connected-vugs- and fractures-dominated pore systems and horizons with microporosity-dominated pore systems that are candidates for secondary recovery processes. The study proposes a total porosity variation model that describes an External Cardiac Compression-like depth profile, showing alternation between low/tight and high porosity horizons, with the highly-porous intervals associated with the solution-enlarged porosity zones. Permeability varies with the pore type-mixing and rock texture type rather than the total porosity. The method well applies to distinguish flow conduits from baffles and barriers in complex carbonate reservoirs.