Perpustakaan Digital ITB

Electrical Submersible Pumps (ESP) are commonly used in oil wells when natural reservoir pressure cannot push fluids to the surface. However, in packerless wells, ESP operations can encounter a problem called flumping— where fluids flow simultaneously through both tubing and annulus. This situation can cause unstable flow, gas backflow, and increase the risk of equipment failure, especially in wells with high gas–oil ratio and dynamic multiphase flow conditions. To address this, this research uses a combination of well performance analysis, ESP design, and flow assurance simulation. The well’s production potential is analyzed using IPR and VLP curves, followed by ESP selection with attention to liquid rates, gas–oil ratio, and water cut. Main calculations include a Productivity Index (PI) of 6.3STB/day/psi and Absolute Open Flow (AOF) of about 13,800STB/day, with pump power needs around 263hp for the selected pump depth and stage. The fluid flow patterns, pressure, and temperature were further examined through multiphase simulation by testing different parameters, such as tubing size, roughness, wellhead pressure, and pump depth. The overall results show that flow regimes like annular and stratified flow are dominant in the annulus, with water cut often above 90%. Changes in tubing design, pump position, or wellhead pressure can trigger unwanted flumping or stabilize production. The most effective mitigation is installing a packer and optimizing operating conditions, which significantly reduces fluid entry into the annulus and gas backflow. This study confirms that a combination of ESP design, operational adjustments, and well-targeted flow assurance can minimize flumping and improve the reliability of oil production in packerless, gas-prone wells.