High water cut and reservoir depletion choked hydrocarbon production from a well that had been a consistent oil producer for several decades. Reservoir analysis determined that significant reserves remained but would require secondary recovery technology, which had been considered uneconomical when the well was originally completed and was considered economically challenging.
During the planning stage, conventional slickline-conveyed gas lift valve (GLV) stinger systems were considered but eliminated as high risk because of the numerous installations (8) required and the need to replace packoffs every 6 to 12 months. Other technologies were also eliminated because they would require the assistance of a workover rig, making them uneconomical.
Project engineers chose a Peak Well Systems gas lift conversion with SIM sealing integrity management system, which could be installed in only three runs and would minimize subsequent maintenance.
The Peak Well Systems engineering team designed a SIM system with GLV straddle including a calibrated carbide choke orifice for gas inflow control and a ceramic ball-type check valve to keep the A-annulus hydrocarbon-free.
During the three-run installation operation, the lower SIM system was set below the target gas injection zone, the tubing punched for A-annulus access, and the upper SIM system and gas lift stinger assembly were latched and sealed to the lower SIM system.
After installation, gas injection was started through the A-annulus, as in a typical gas-lifted well, delivering oil production in the range of initial postcompletion rates.