Abstract In carbonate rocks, establishing rock-types that honor both geology and petrophysics is always a challenge. This is mainly due to intrinsic pore system heterogeneity and sensitivity to diagenetic alterations. Furthermore, some routine and/or special core analyses are destructive and time consuming. Over the last decade, non-destructive micro computed tomography supported the development of digital rock physics techniques, enabling pore system observation and fluid flow modeling, with high resolution and limited to no damage to the rock samples. The studied interval includes the Valanginian (Lower Cretaceous) Buwaib Formation of Saudi Arabia. In this study, standard petrography techniques such as thin-section observations and Scanning Electron Microscopy (SEM) were integrated with state-of-the-art micro-computed tomography observations and digital rock physics simulations. Those data were further compared with plug-scale measurements such as Mercury Injection Capillary Pressure (MICP) data to validate the models. This workflow was designed in order to establish a rock-based rock-typing scheme that would integrate both geology and petrophysical data and enable refined hydrocarbon saturation estimates. Studied deposits include intertidal mudstones and wackestones, usually pervasively dolomitized microporous. Diagenetic studies reveal that dolomite formed at an early stage with limited influence of burial diagenesis. Under SEM, dolomite fabrics are very finely crystalline with euhedral rhombs. Micropores are abundant and well connected, but the presence of detrital clays locally increases the tortuosity of the pore system suppressing connectivity. Based on those observations, the integration of the CCA and MICP data lead to the characterization of several rock-types with their own petrographic and petrophysical characteristics. A comprehensive digital rock physics workflow was utilized to produce 3D rock models through multi-scale 3D X-ray microscopy, and application of a machine-learning algorithms, to characterize the internal fabric of the rock samples based on the abundance of microporosity. Numerical simulation of the electrical current flow through the samples showed the variation of Archie's saturation exponent "n" with water saturation. The meso- and macropores were found to produce the moveable hydrocarbons due to their lower capillary pressure, whilst the micropores hold immobile formation water. The digital models were then used to simulate the drainage of the relative permeability to identify water saturation changes affecting the timing of first water flow in subsurface. Multiphase flow and electrical properties derived from digital experiments indicate that pore structure and sizes are major controls on them in this carbonate formation. Variable saturation exponent values indicate the Archie model may not be appropriate for resistivity log-based water saturation calculation. Saturation calculation could be significantly refined, if wireline petrophysical models are calibrated using digital rock analysis data.
Perière et al. (Tue,) studied this question.
Synapse has enriched 5 closely related papers on similar clinical questions. Consider them for comparative context: