Gas Lift

Gas lift is the primary artificial lift system utilized across approximately 2,000 wells in Oxy’s Delaware Basin assets. As the number of wells increase and personnel resources remain constrained, production engineers frequently focus on resolving urgent operational issues, such as well or equipment failures. This situation results in limited time for consistent and proactive surveillance and analysis of well performance.

Alternatives to Sucker Rod Pumping (ROD) are being sought as late-lift Artificial Lift (AL) solutions for lower Gas Liquid Ratio (GLR) horizontal wells. This is due to the higher ROD lift failure rates seen for pad-drilled horizontal wells in the Midland Basin and in Unconventional fields in general. These pad-drilled wells often exhibit challenging wellbore geometry (severe doglegs) which makes it difficult for ROD lift which is plagued more frequent and costly failures and often the pump is required to be set higher than desired.

Gas lift remains a cornerstone of artificial lift technology, particularly for addressing challenges in high Gas-Liquid Ratio (GLR) wells and heavily deviated wellbore geometries. However, declining reservoir pressures, high water cuts, and limited gas compression capacity present significant operational challenges. Coupled with increasing emphasis on cost efficiency and sustainability, these factors necessitate innovative solutions to maintain production and optimize lifting costs.

High Pressure Gas Lift (HPGL) has established itself as a viable and valuable high-rate artificial lift method well suited to the challenges in modern unconventional production environments. Operators across all unconventional basins in North American unconventional basins are increasingly turning to HPGL to help them produce wells, especially during the initial production (IP) phase of the well’s life.

The Eagle Ford, Bakken and other operating areas often prove to be challenging areas for the successful, long-term operation of gas lift valves due to numerous factors which may compromise the efficiency of the installation and reduce production and life expectancy of the valve. These factors may include well bore heat, well bore fluids and gases, well bore contaminants and debris, offset fracturing activity, natural formation pressure and introduced, non-naturally occurring pressure. 

Electric Gas Lift (eGL) is a relatively new artificial lift method. While fundamentally similar to traditional gas lift, using gas to aid in the production of wellbore fluids, the operating principle of the valves are different. Traditional gas lift systems use nitrogen charged bellows to open and close the valves at certain wellbore conditions, whereas electric gas lift valves (eGLVs) function by electro-mechanical means, such as an electric motor or solenoid.

Gas lift optimization enhances production efficiency by maximizing uplift and reducing operational costs by addressing common issues such as over-injection. Numerous majors and others admit that over injecting is a serious problem affecting produced oil rates and 30-50% overuse of injection gas. Key steps include gathering well parameters, monitoring casing and tubing pressures with data loggers, and measuring static bottom hole pressure (SBHP) to assess true well conditions. This process integrates field data collection, real-time monitoring, and advanced analytical tools.

Sucker rod pumping is the main artificial lift system used to exploit the unconventional Vaca Muerta formation situated in the province of Neuquén, Argentina. 

The efficient management of gas lift systems is pivotal in minimizing operational costs and maximizing production for a large majority of unconventional wells. By leveraging automated workflows to efficiently build and tune physics based nodal analysis models, operators can optimize well performance and gas injection rates thus reducing operational expenses. A cornerstone of effective gas lift optimization is the seamless integration of real-time data with physics-based models.

During intermittent gas lift, a low-density fluid (gas) is used to lift a high-density fluid (oil) from the bottom of the well to the surface. As a result of the oil having a higher density than the gas, some amount of the oil falls back in the form of droplets or in a film along the wall of the tubing to join the next slug of oil. However, there is still no method to accurately estimate the fallback factor in the presence of several variables in the process.