Miguel Irausquin, Mohammad Masadeh, Nelson Ruiz and Oswaldo Robles
Baker Hughes
Electric Submersible Pumps (ESPs) are severely affected by free gas entering the pump, which cause significant degradation in pump performance, due to gas locking conditions cause by bubbles blocking the fluid from passing through the impellers, resulting in frequent shutdowns and restarts, which increase the risk of early failure. This effect is even worst when a gas slug event, very common in horizontal wells drilled in unconventional reservoirs, hit the system, this event consist of a large volume of light density fluid (gas) flowing through the system, overheating the motor and pumps due to a no liquid flow condition, resulting in unstable production due to ESP shutdowns caused by underload or high motor temperature. The industry has used shrouds, rotary and vortex gas separators, and more recently, multiphase pumps to handle the gas, however, there are some applications where this equipment is not enough to handle the Gas Liquid Ratio (GLR). Recently two Oil Operator Companies in the Permian basin following our recommendation successfully installed a multiphase encapsulated production solution technology to separate the gas from the liquid in the wellbore. As produced fluids, pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively (> 90% of efficiency), stabilizing operations within a certain operating window. In this document, results are shown for two successful field cases, how uptime improved, being able to reduce the number of shutdowns, improving operational performance and increase the drawdown maintaining stable production of the wells.