Iranian Journal of Oil and Gas Science and Technology

Abstract Electrical Submersible Pumps (ESPs) are widely used to sustain oil production in mature and challenging reservoirs; however, their frequent failures often lead to production deferment, costly workovers, and reduced operational efficiency. This study presents a comparative evaluation of predictive maintenance (PM) and reactive maintenance for ESP systems using 50 case studies from diverse reservoirs and operating conditions. Reliability performance was assessed using mean time between failures (MTBF), mean time to failure (MTTF), failure rate, Kaplan–Meier survival analysis, and Weibull probability modeling. The economic impact of maintenance strategy was also evaluated through failure-related costs and deferred production losses.

The results indicate that PM consistently enhances ESP reliability by extending operational run life and reducing failure occurrence. Median survival increased from approximately 400 days before PM implementation to about 750 days after PM adoption, while Weibull analysis showed a shift from early random failures toward more predictable wear-out behavior. Economic evaluation further demonstrated that PM reduces workover frequency and production-loss exposure, yielding estimated cost savings of approximately 30–40% across the analyzed cases, even after accounting for monitoring and diagnostic investments.

This study contributes to the ESP reliability literature by providing an integrated comparison of predictive and reactive maintenance using survival analysis, Weibull modeling, and economic assessment within a unified framework across multiple field cases. The findings confirm that predictive maintenance is both technically effective and economically justified, and they highlight the value of combining advanced monitoring, reliability analytics, and data-driven maintenance planning to improve ESP performance and reduce life-cycle costs in oilfield operations.

Abstract Due to the limitations of existing natural gas fumigation systems, including the bypass and injection systems, there is a need for the design of a new system with fewer restrictions. This paper addresses this issue by conducting a thermodynamic analysis of the performance of a new system, called the ejector gas perfuming system, across a wide range of parameters, including primary gas pressure (Pg = 500-5500 kPa) and secondary gas pressure (Ps = 200-400 kPa). The results demonstrate that the ejector's performance is primarily influenced by two key factors: the pressure at the ejector's exit and the ejector's entrainment ratio. The findings indicate that the ejector performs optimally when Ps > 250 kPa and 1850 kPa ≤ Pg ≤ 5200 kPa. Outside of this range, its performance declines.

Abstract One of the most important methods for enhancing oil recovery in reservoirs is chemical flooding. The performance and efficiency of these processes in increasing oil recovery depend on several factors, including the rock and fluid properties of the reservoir. Therefore, a critical step in evaluating the effectiveness of these methods is conducting laboratory studies and calculating the potential of chemical agents to recover oil. Optimal design, using new approaches such as novel chemical agents or comprehensive studies of chemical flooding at the core scale, is essential to make chemical flooding more cost-effective.
For this purpose, a laboratory study combined with integrated simulation was performed to identify the effective mechanisms in low-salinity water–polymer injection and to determine the necessary and dominant conditions for improving recovery in Iranian carbonate reservoirs. Initially, four injection scenarios were tested in the laboratory: water injection–polymer injection–low-salinity water injection, water injection–low-salinity water injection–polymer injection, water injection–low-salinity water–polymer injection, and low-salinity water injection–low-salinity water–polymer injection. Subsequently, low-salinity water–polymer flooding was simulated using the Eclipse 100 simulator to evaluate the effect of polymer injection on oil recovery and oil trapping in the reservoir rock. Finally, simulation results were validated against laboratory data.
The results demonstrated that low-salinity water injection followed by low-salinity water–polymer injection showed the best performance, improving secondary oil recovery by 63.45%, with wettability alteration identified as a key mechanism for enhanced oil recovery. The study also showed that under optimal conditions, despite mechanical degradation of the polymer, recovery of initial oil in place could reach up to 85% through controlled adsorption of polymer on the rock surface. Furthermore, initial polymer injection was found to help reduce the amount of polymer required to achieve residual oil saturation.