Maximizing Well Productivity through Hybrid Gas Lift Optimization
In a mature offshore oil field, production decline was caused by well performance and high corrosion risk from CO₂ and H₂S. A retrofit project proposed a continuous gas lift system combined with predictive monitoring analytics. The solution increased well uptime from 88% to 97%, boosted oil output by 26%, and reduced annual maintenance costs by 18%.
Project background
The project was carried out in a mature offshore field in the Gulf of Mexico, producing from a depth of approximately 15,000 ft at 300–310°F. The well fluid contained 3.82 mol% CO₂ and 2.99 mol% H₂S, posing significant corrosion and operational challenges. The operator sought a reliable lift method that would extend production life, maintain pressure control, and reduce intervention frequency. Simultaneously, the engineering team investigated technology transfer to geothermal production systems facing similar high-temperature conditions.
Challenge
The existing gas lift system suffered from:
- Frequent gas valve failures due to corrosive gas composition
- Unstable flow regimes causing production fluctuations and slugging
- Safety concerns related to gas injection into the annulus of aging casings
- A need for real-time monitoring to optimize lift efficiency without increasing operational cost
Failure to stabilize lift performance would risk progressive scaling, tubing damage, and a 20–25% production shortfall.
Solution
The team implemented a continuous gas lift redesign supported by digital well surveillance.
Key steps included:
- Installing retrievable packer assemblies and a new gas lift mandrel system compatible with 4½" production tubing
- Redirecting gas injection through a velocity string to isolate the inner casing from corrosive gas, reducing metal exposure
- Integrating pressure and temperature sensors linked to a cloud-based monitoring dashboard for real-time control
- Performing simulation and nodal analysis to optimize injection rates between 2,000–4,000 Mscf/d at discharge pressures of 1,750–2,500 psi
The concept was later piloted in a geothermal production well to test gas injection as a method for circulation enhancement and scaling prevention.
Results and Impact
| Indicator | Before | After | Improvement |
|---|---|---|---|
| Well Uptime | 88% | 97% | +9 points |
| Oil rate | 1,250 BOPD | 1,575 BOPD | 26% |
| Maintenance cost | — | — | -18% |
| CO₂ exposure | High | Reduced 45% | — |
- Stable lift performance achieved under high-temperature and corrosive gas conditions.
- Reduced intervention frequency due to retrievable valve system.
- Predictive monitoring enabled proactive gas rate adjustment, preventing flow instability.
- The geothermal test confirmed similar benefits for heat extraction efficiency and system stability.
Lessons Learned / Key Takeaways
- Isolating corrosive gas from casing flow paths significantly improves system reliability.
- Predictive analytics and real-time pressure data are essential for proactive lift optimization.
- Gas lift system modularity allows cross-application between oil & gas and geothermal operations.
Broader Significance / Sustainability
This project demonstrated that optimizing artificial lift in conventional wells can directly support low-carbon energy transition goals. The hybrid CGL–geothermal adaptation offers:
- Reduced CO₂ emissions per produced barrel
- Reusability of oilfield infrastructure for geothermal repurposing
- Energy efficiency improvements aligned with sustainable production objectives
Quick Facts
Location
Gulf of Mexico
Depth
15,000 ft
Temperature
310°F
Lift Method
Continuous Gas Lift (Hybrid Adaptation)
Key Results
Improved production stability and efficiency
Year
2025
Country
Mexico
Production Methods
ESP