As the demand for natural gas is increasing, the exploration and appraisal activities for unconventional gas resources is expanding and becoming significant to fulfill the global demand. These Unconventional resources are known to have complex geochemistry and rock physics. Understanding the complex nature of unconventional rocks is challenging and requires comprehensive integration with an advanced reservoir characterization approach. In this study, a comprehensive integrated rock characterization workflow was designed to understand the challenges and uncertainties associated with the Diyab Formation unconventional rocks.
More than 800 ft of unconventional cores were analyzed to characterize the Jurassic carbonate succession of Jubaila, Hanifa and Tuwaiq Mountain Formations through an integrated workflow. The workflow includes core and OH logs based initial rock classification through machine learning known as "Heterogeneous Rock Analysis" (HRA). Based on HRA, the samples selection for Unconventional and advanced Geomechanical core analysis was applied, followed by core data interpretation, core to logs integration and refining reservoir quality. Unconventional and advanced core analysis in this workflow include but not limited to following types, liquid TRA, TOC, HAWK, Vitrinite Reflectance (VR), Core-NMR T2, MICP, 2D/3D SEM, Dean Stark, XRD/XRF, Geomechanics (Brazil Tensile Strength, Unconfined Compression (UCS), Single (TXC) and Multi Stage Triaxial (MTXC), Multi-Stress Compression (MSC), Biot coefficient test), etc. Core analysis results were interpreted and integrated with the logs to better understand and characterize the unconventional reservoir qualities.
Sample selection was performed using all available data, to capture the variations in petrophysics as well as geomechanics and geochemistry, particularly organic matter content, and mineralogy within each identified petrophysical rock class. Core logs, plug analysis, and wireline data have been integrated and generally showed excellent agreement within the range of associated uncertainties, which can be attributed to rock tightness and resolution variations. Geochemistry (TOC, HAWK & VR) shows high concentration of kerogen, initially of type IIS but presently with low HI in which maturity reflects the dry gas window and possible condensate. Porosity ranges from 2.7% to 8% with a maximum reading reported from MICP data. The 2D & 3D SEM images provided some key findings, associated with different porosities either connected, isolated and/or organic matter porosity systems in given samples. These complex porosities systems cannot be captured by only conventional methods. The organic type of porosity is important as it provides further support to matrix porosity connectivity. Integrating this knowledge with logs, geochemistry, petrophysics and mineralogy helped to refine the initial characterized rock properties. In addition, the geomechanical understanding took the integration step further to identify potential zones for fracking and testing based on the classified stress regime.
