Thomas Trentadue, Dane Laird, and Alberto Dominguez Fernandez, Coterra Energy
Simon Suarez and Zach King, Flowco
This study evaluates a 3-1/2 in. tubing well converted from continuous gas lift to plunger-assisted gas lift (PAGL) using a bypass plunger that initially failed to complete cycles under flowing conditions. The objective is to diagnose the root cause, determine operational boundaries for PAGL in 3-1/2 in. tubing, and assess the feasibility of PAGL relative to tubing replacement and higher gas-injection strategies using field data and plunger lift mechanistic models.
Steady-state multiphase flow simulations and drag-based mechanistic models were used to estimate plunger fall and upstroke velocities along the well, cycle durations, and kinetic energy at impact. Model results indicated that a 14-in. bypass plunger should be able to fall against flow rates exceeding 2 mmscf/d for this well. However, field data showed that the custom 3-1/2 in. tubing plunger had an undersized inner orifice, making it too restrictive to fall against flow. Consequently, prolonged shut-in times were required, which increased bottomhole pressure and reduced production. After deploying a proportionally designed bypass plunger with a larger inner orifice, PAGL operation stabilized with a 2-minute shut-in and production increased.
This paper presents a comparative study demonstrating that continuous-flow plunger deployment in larger tubing can provide a cost-effective alternative to tubing replacement, enabling operators to reduce gas injection while avoiding liquid loading.