Iranian Journal of Oil and Gas Science and Technology

Abstract The mechanisms of Low-Salinity Water (LSW) flooding in carbonate reservoirs remain less well understood than in sandstones. This study investigates the role of rock composition through a comparative experimental analysis of genuine limestone from the Shadegan oil field and pure synthetic calcite. Core flooding tests, contact angle measurements, zeta potential analysis, and pH monitoring were conducted under reservoir conditions (70°C, 100 bar). Results show that tertiary LSW injection recovered 14.5% of the initial oil in place in limestone, compared to only 3.4% in pure calcite. This significant difference is attributed to a more pronounced wettability shift towards water-wet conditions (42° contact angle reduction vs. 16° in calcite), driven by a stronger negative zeta potential shift (-7.7 mV vs. -4.1 mV) in the genuine rock. XRF analysis revealed the presence of silica, sulfate, and phosphate impurities in the limestone, which amplified the surface charge alteration. The study concludes that trace non-clay minerals significantly enhance LSW efficacy in carbonates, providing new insights for optimizing EOR in complex carbonate formations.

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 The increasing demand for hydrocarbons has prompted new recovery strategies by applying nanoparticle–surfactant flooding in chemical-enhanced oil recovery (CEOR). Some mechanisms that improve oil mobility are rock wettability alteration and reduced interfacial tension between the oil and water. In this work, silica (SiO₂) nanoparticles (NPs) were synthesized and characterized, and their effect on wettability alteration and interfacial tension (IFT) between the oil and SiO₂ nanoparticles (NPs) dispersed in sodium dodecyl sulfate (SDS) solutions was determined. Experiments on oil displacement by flooding with brine and NPs dispersed in an SDS solution were investigated in a micro glass model. X-ray diffraction (XRD) pattern and scanning electron microscopy (SEM) confirmed the mineral structure and platy polycrystalline morphologies that gave an estimated particle size of 88 nm using Scherrer’s formula. Fourier transform infrared spectroscopy (FTIR) showed characteristic symmetric and asymmetric stretching vibrations. The measured wettability alteration and IFT showed changes in wettability from water-wet toward a more water-wet condition and decreased IFT, respectively, as the SDS concentration increased. The optimum oil recovery of 67.45% was obtained at 2.08 mM SDS when SDS concentrations were varied (2.08, 6.25, 8.33, 10.42, and 14.58 mM) at a constant concentration of SiO₂ NPs (0.1 wt %). Having obtained the optimum oil volume from OOIP at 2.08 mM SDS, SiO₂ NPs concentration varied (0.05, 0.1, 0.15, 0.2, and 0.25 wt %) at a constant SDS concentration (2.08 mM). This optimized approach gave an excellent total oil recovery of 78.36% at 0.2 wt % SiO₂ NPs. Therefore, 0.2 wt % SiO2 NPs with 2.08 mM SDS should be applied in oil recovery.

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.

Abstract Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention, and blocking the pore throats. This study strengthens our understanding of the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. To this end, a transport approach utilizing the kinetic Langmuir model is developed and validated using experimental data. After that, the effects of reservoir rock type and its properties (clay content and grain size), the salinity of injected fluid, and the reservoir temperature on the transport and retention of nanoparticles in porous media concerning enhanced oil recovery methods are investigated. Since the concentration of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. Brine salinity also has the most significant impact on the amount of nanoparticles deposited on the rock surface. The surface covered by nanoparticles increased from 10% to 82% after changing salinity from 3 wt % NaCl to the API brine. 

Abstract Enhanced oil recovery (EOR) is a vital part of the process of oil production from sandstone and carbonate reservoirs. Maintaining and increasing oil production from many fields require proper selection, design, and implementation of EOR methods. The selection of EOR methods for specific reservoir conditions is one of the most difficult tasks for oil and gas companies. Screening of different EOR techniques considering previous experiences from the methods applied in other fields is a first step in the recommendation of any costly EOR operations. In this paper, EORgui software was utilized to screen eight enhanced oil recovery methods in one of Iran’s offshore sandstone oil fields. The reservoir is composed of two sections with different fluid properties, namely API, viscosity, and oil composition, but relatively homogeneous rock properties and high permeability (1500 mD). The results show that polymer flooding is technically the most suitable enhanced oil recovery method in the upper zone of the reservoir with a high percentage matching score of 90%, and immiscible gas injection with a matching score of 83% is ranked second. For the lower part of the reservoir containing a fluid with much higher viscosity, immiscible gas injection (83% matching) can be recommended. Furthermore, polymer flooding predictive module (PFPM) was utilized to investigate the impact of polymer concentration on oil recovery performance of the upper part with an ultimate recovery of about 40% at the optimum concentration.