<![CDATA[In oil and gas production, horizontal wells are increasingly used to enhance reservoir performance by placing a longer wellbore section within the reservoir. These wells often adopt specific inclinations either upward-sloping or downward-sloping terminal sections to align with formation dip and minimize issues such as liquid loading. However, undulating trajectories in horizontal wells may lead to challenges such as liquid accumulation in downward-sloping sections and gas entrapment in upward-sloping sections, potentially reducing production efficiency. This study aims to predict fluid production rates and analyze multiphase flow behavior in horizontal wells with varying wellbore inclinations using a production simulator. Four scenarios were modeled: Original, True Horizontal, Upward-Inclined End (95° and 100° inclination), and Downward-Inclined End (80° and 85° inclination). The study utilized 20 deviation survey data points from Well F-14 in Field ‘V’ to construct the well trajectory models, adhering to the simulator’s input limitations. Simulation results indicate that the upward-inclined configuration with a 100° inclination achieved the highest oil production rate (9401.8 STB/day), outperforming other scenarios in both oil and gas flow rates. The enhanced performance is attributed to gravitational assistance in fluid movement and reservoir pressure expansion. In contrast, the downward-inclined geometry yielded the lowest production due to higher liquid holdup. Gradient matching was employed to identify dominant flow patterns and slip velocities, revealing bubble flow dominance in horizontal sections and transition to slug flow in mid-well segments. These findings highlight the importance of well trajectory design in optimizing multiphase fluid flow and maximizing production in horizontal wells.]]>
