Deploying gas lift valves (GLVs) in high-pressure Midland Basin wells with prolonged, high-rate annular flow posed significant hurdles. Conventional 3.5” tubing gas lift installations increased initial Capex by over $20k per well due to larger tubing costs and required higher gas compression, leading to elevated emissions and electrical usage.
Delaying GLV installation until natural flow declined introduced logistical complexity and risked lost production time due to unpredictable flow deterioration. Early GLV installation without protection led to valve damage from debris (sand, frac plug remnants), necessitating costly tubing swaps. The operator sought to reduce Capex, emissions, and electrical usage while maximizing early drawdown and maintaining time-to-market (TTM) efficiency without planned tubing downsizing.
A dissolvable valve barrier, compatible with standard 1” GLVs on 1.5” mandrels, was deployed with a wireline-set 8k 5.5” dissolvable packer and pump-out plug (pinned at 1725 psi) to protect GLVs during 45 days of high-rate annular flow and provide temporary pressure isolation during installation.
The barrier, made from a slow-dissolving alloy tuned to annular fluid, temperature, and salinity, shielded valves from debris-laden flowback, dissolving predictably to enable gas injection without intervention. A flapper check in the tubing mitigated pressure control risks. The system, tested in a single-well trial in the operator's Midland Basin operations (7” x 5.5” casing, 11,800’ TVD, 2700 BFPD), allowed 2-7/8” tubing use and annular flow before converting to gas lift after 45 days.
Field data from the trial showed the dissolvable valve barrier and packer system reduced tubing costs by 52% by using 2-7/8” instead of 3.5” tubing, cut emissions and electrical usage by 33% due to lower compression needs, and maximized early production (outperforming pad offsets in cumulative oil and fluid). It enabled day-one GLV installation, avoiding valve damage and tubing swaps, maintained TTM efficiency, and eliminated planned workovers.
The system supported a seamless transition to gas lift at 1000 BFPD, with normal valve performance post-dissolution. Collaboration with the operator and their preferred gas lift provider established a repeatable process, with plans for further trials in 5.5” and 7” casing wells.
