Unconventional shale reservoirs hold vast hydrocarbon resources, but productivity is constrained by ultra-low matrix permeability and complex fracture behaviour. While horizontal drilling and hydraulic fracturing are essential for commercial production, optimizing estimated ultimate recovery (EUR) remains challenging due to coupled interactions among permeability, pressure depletion, fracture effectiveness, and well interference. This study uses compositional reservoir simulation to numerically investigate how hypothetical matrix permeability enhancement and parent-child well interactions affect cumulative gas production. Models were built using Eagle Ford shale properties with multi-stage hydraulic fractures and geomechanical effects. Matrix permeability was increased by factors of 10× and 100× relative to the base case, and bottom-hole pressure (BHP) was optimized across 100 synthetic scenarios. Results show that matrix permeability is the primary control on long-term production, with higher permeability significantly improving matrix-to-fracture fluid transfer. The optimal single-well scenario produced approximately 9.8 × 10⁸ ft³ of gas. Geomechanical analysis revealed uneven strain distribution around fractures, indicating non-uniform stress redistribution. In the parent-child configuration, strong pressure interference was observed; notably, the child well outperformed the parent well under simulated conditions, likely due to greater pressure drawdown and enhanced fracture connectivity. This study establishes theoretical upper-bound recovery limits through hypothetical permeability scenarios rather than proposing field-ready technologies. The findings emphasize that maximizing EUR requires an integrated evaluation of permeability, fracture effectiveness, pressure management, geomechanics, and well spacing.
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