Fluid flow and permeability analysis of tight gas carbonate reservoir rocks using fractures and dynamic data

The porosity, permeability, rock material and fracture networks of the newly discovered tight carbonate reservoir rock, Early Cretaceous Sarmord Formation in Zagros basin are examined. methods used to investigate formation cores, micro-resistivity image logs, drill stem tests, drilling fluid data, petrophysical wireline data drilled cutting samples. analysed show that is characterized by extensive open partially macro-fractures formed local stress from fault fold propagation. These fractures sub-vertical with an average dip 73°, aperture 0.44 mm persistence (length) 11.0 cm. dominant strike NE-SW, parallel observed faults perpendicular main Miran West structure. vast majority porosity was found be matrix, having very limited impact (average 0.032%) on porosity. In contrast permeability averages 240 mD which four orders magnitude greater than matrix permeability. As a result, inter-connected create effective flow pathways enhanced hydrocarbon migration Faulting associated field structure led damaged zones act as higher preferential pathways. It demonstrated driven spacing, whilst has control findings this study highlight importance reservoir's quality gas bearing rocks. network fractures, provide controls pore spaces storage. This work emphasizes understanding structural geology reservoirs.