.pdf asset-performance field_planning_color fit_for_purpose_color production_optimization_recovery_color kpi-box kpi-money kpi-time ::before

An operator in the Permian basin was experiencing electrical submersible pumping (ESP) system failures in an unconventional horizontal well producing from the Wolfcamp formation, due to gas slugs in the production stream. The well had a high gasto- liquid ratio of 1,700 SCF/STB, a low flow rate of 219 BFPD, and was completed with 5-½ in. 17 lb casing.

Unconventional horizontal wells present unique production challenges, particularly gas slugs that accumulate in the high side of undulations in the lateral section and then break free. These gas slugs affect the operation of ESP systems, causing gas locking conditions that shutdown the system and/or pump cycling that can lead to motor overheating. These issues shorten the life of the ESP system and limit oil production.

The operator contacted Baker Hughes, a GE company (BHGE), for a solution to improve ESP performance in the well. After reviewing the production data, BHGE Artificial Lift Systems engineers recommended the slimline patented* CENesis™ PHASE multiphase encapsulated production solution, featuring a 300 series FLEXPump™ 6 production pump combined with a GI™ gas insurance boost pump.

Download the PDF to read the full case study.

Challenges & Results


  • High gas-to-liquid ratio of 1,700 SCF/STB
  • Gas slugging conditions
  • Low flow rate
  • 5-½ in. casing


  • Increased oil production 71 BOPD
  • Improved reservoir pressure drawdown to 460 psi from 550 psi with previous competitor’s system
  • Eliminated ESP system gas locking due to gas slugs