Microbial enhanced oil recovery (MEOR) refers to the process of using bacterial activities for more oil recovery from oil reservoirs mainly by interfacial tension reduction and wettability alteration mechanisms. Investigating the impact of these two mechanisms on enhanced oil recovery during MEOR process is the main objective of this work. Different analytical methods such as oil spreading and surface activity measurements were utilized to screen the biosurfactant-producing bacteria isolated from the brine of a specific oil reservoir located in the southwest of Iran. The isolates identified by 16S rDNA and biochemical analysis as Enterobacter cloacae (Persian Type Culture Collection (PTCC) 1798) and Enterobacter hormaechei (PTCC 1799) produce 1.53 g/l of biosurfactant. The produced biosurfactant caused substantial surface tension reduction of the growth medium and interfacial tension reduction between oil and brine to 31 and 3.2 mN/m from the original value of 72 and 29 mN/m, respectively. A novel set of core flooding tests, including in situ and ex situ scenarios, was designed to explore the potential of the isolated consortium as an agent for MEOR process. Besides, the individual effects of wettability alteration and IFT reduction on oil recovery efficiency by this process were investigated. The results show that the wettability alteration of the reservoir rock toward neutrally wet condition in the course of the adsorption of bacteria cells and biofilm formation are the dominant mechanisms on the improvement of oil recovery efficiency.

Fluid/fluid and fluid/rock interfaces have large influence on the microscopic sweep efficiency of an enhanced oil recovery process. Therefore, modification of these interfaces using nanoparticles to suitable conditions might lead to better recovery factors. Particularly, wettability alteration and interfacial tension reduction are the two key mechanisms which should be considered. This study was designed to address the capability of nanoparticles to be used as a chemical agent for enhanced oil recovery by several core flooding experiments. The injected chemical solution was prepared using synthetic brine containing %3 NaCl, silica nanoparticles, and SDS surfactant. Contact angle in rock/oil/solution system and interfacial tension between oil/solution were measured. In addition, SEM pictures and XRD analysis were taken to conduct a more thorough investigation of effect of nanoparticles on sandstone core plugs. Nanoparticles and surfactant mixture were flooded with various concentrations under different scenarios. The results show the incremental oil recovery of nanoparticles floods in sandstone core samples which ranged from 4.85 to 11.7%. Conversely, the enhanced oil recovery of high concentration of nanoparticle floods in cores was small. It is deduced that the mechanisms responsible for incremental oil recovery are mainly interfacial tension reduction and wettability alteration toward water-wet condition. However, the flooding results as well as experimental study of possible retention revealed that nanoparticles can be considered as an effective chemical agent in enhanced oil recovery.

The rapid escalation of anthropogenic CO2 emissions at the same time as the growth in energy demand has brought the importance of CO2 enhanced oil recovery (EOR) into the spotlight. Nevertheless, fundamental problems with conventional CO2 injection have paved the way for practicing other strategies, such as carbonated waterflooding (CWF), i.e., flooding of CO2 dissolved in flood water through the reservoir. In this work, performance of CWF as a joint method of EOR and CO2 storage in an Iranian oil field is examined through sets of coreflooding experiments, conducted at a specified pressure and temperature condition on two different reservoir oil (light and heavy) and rock (carbonate and sandstone) samples from the investigated oil field. In summary, CWF improved the oil recovery as compared to waterflooding (WF). Average recovery factors (RFs) for CWG ranged from 6.4% to 13.6% when implemented as a secondary recovery technique and 4.2% to 4.8% when used as a tertiary recovery technique. This improvement was also higher in the carbonate rock than in the sandstone one, slightly higher with light oil than with heavy oil, and lower when a more saline brine was used for carbonated water preparation. CWF also showed to be more effective when implemented in a mixed‐wet system than in a water‐wet one. Moreover, considerable amounts (about 42‒60%) of the CO2 injected through the flooding brine were ultimately stored in the porous media. Finally, a co‐optimizing function was used as a standard for coupling CO2 EOR and storage. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

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