Abstract The primary objective of this paper is to introduce fit-for-purpose technologies and best practices aimed at increasing the productivity of the Mauddud formation in the Greater Burgan Field, Kuwait, through detailed geomechanical modelling, natural fracture prediction, and a dual-porosity / dual-permeability reservoir model. Objectives include constructing a discrete fracture network and a 3D geomechanical model to better understand reservoir fluid flow and select sweet spots for new horizontal infill wells. The 3D geomechanical model provided the foundation for stress modelling and fracture design. It incorporates natural fractures based on numerical fracture prediction techniques, with faults and fractures embedded into a 25 million grid cell geomechanical grid. A new compressional/shear slowness correlation was established and served as the input for Young’s Modulus, Poisson’s Ratio, uniaxial compressive strength, tensile strength and friction angle modelling. These results were derived by a mix of co-kriged properties, machine learning from extensive laboratory and field data. Blind test models cross-validated against field data proved the model calibration, though the friction angle correlation was limited by data availability. The vertical stress gradient averages at ~0.98 psi/ft; pore pressure ranges from 0.44-0.48 psi/ft. The maximum horizontal stress is oriented ~40-50° from North. The modelling of fracture height is mainly controlled by local stress magnitudes and the surrounding shale formation, with advanced fracture modelling separating the different types of fractures into fractures related to shear and joint tectonic activity; fractures around the fault damage zone; and fractures derived from seismic attributes to capture the heterogeneity and complexity of the field. It was discovered that pressure communication between the two reservoirs, BGSU and Wara, is likely. Main recovery is driven by natural fractures, low matrix permeability, and pressure depletion. Based on the geomechanical model, optimal well placements were suggested for more than 100 planned wells.
Al-Enezi et al. (Mon,) studied this question.
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