• High gas-to-liquid ratio (>4,500 SCF/STB)
  • Gas slugging
  • Potential for motor overheating and pump gas locking
  • Wide flow range (3,000 down to 200 BFPD)
  • Fluctuating fluid density
  • Remote location with inconsistent electrical generation
  • Lack of three-phase power to the wellsite
  • Removed fluids quickly to increase gas production from 1,900 MMcf/d to 4,500 MMcf/d and to increase oil production from 177 BOPD to 396 BOPD
  • Extended ESP run life by 200+ days or 73% compared to the average ESP run life in similar applications
  • Lowered bottomhole pressure significantly compared to gas lift

Case study details

Baker Hughes was approached by a major operator in the Texas Panhandle to help deliquefy a natural gas well. The challenge was to quickly unload completion fluids and to lower the bottomhole pressure in the well with an electrical submersible pumping (ESP) system to enable production of up to 4,500 MMcf/d and 396 BOPD.

The operator had been using gas lift, but this form of artificial lift was unable to sufficiently lower bottomhole pressure. The well had a wide flow range from 3,000 BFPD to 200 BFPD and a high gas-to-liquid ratio of >4,500 scf/stb. Typically, such large volumes of gas create gas locking conditions in ESP systems as well as motor overheating when the gas displaces fluid flowing past the system—both of which negatively impact the reliability of a standard ESP system.

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