Oil production from matured crude oil reservoirs is still associated with low recovery factors. Chemical enhanced oil recovery (EOR) is one of the techniques which can significantly improve the recovery factor of the trapped oil. This is mainly achieved by lowering the interfacial tension (IFT) of the crude oil−brine/aqueous chemical and increasing the viscosity of the injected fluid. Nanofluids have demonstrated potential in this respect, and we thus examined how such nanofluids behave when formulated with standard oilfield polymers, with a particular focus on their EOR efficiency. In this work, silica (SiO 2 ) nanofluids with (NSP) or without (NP) surfactant (sodium dodecyl sulfate) added and with varying nanoparticle concentration were formulated with polyacrylamide (PAM) and characterized by DLS and ζ-potential measurements. These nanofluids were then tested in EOR core-flood experiments. Various studies involving the stability and viscosity of nanofluids, interfacial tension of the nanofluidcrude oil system, their effect on wettability alteration, and efficiency for EOR studies as a function of temperature have been reported. The efficiency of the nanofluid systems for IFT reduction and EOR has also been compared with the conventional polymer (P) and surfactant−polymer (SP) flood schemes. The SiO 2 nanofluids significantly increased oil recoveries, particularly at higher temperatures, mainly due to IFT reduction, fluid viscosity increase, and wettability alteration (from intermediate-wet to strongly water-wet). We conclude that SiO 2 nanofluids can potentially be attractive EOR chemicals, particularly for wettability alteration operations and high temperature applications.

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Understanding the kinetics of gas hydrate formation and dissociation in porous media has become important since their discovery in permafrost locations and marine sediments. Natural gas hydrates are now recognized as a huge potential source of methane gas. The present work is focused on understanding the kinetics of methane hydrate formation and dissociation in pure water and seawater. Methane gas hydrate formation and dissociation kinetics were studied in Toyoura sand (100–500 μm) with pure water at 8 MPa (driving force of 4.2 MPa) and seawater at 8 and 10 MPa (driving force of 6.2 MPa) and a temperature of 277.15 K. For the present work, 3.03 wt % saline seawater obtained from Pulau Tekong (Singapore) is used. The methane hydrate formation kinetics in Toyoura sand and 100% pure water saturation at 277.2 K and 8.0 MPa was found to agree well with the literature works. For experiments conducted at 277.2 K and a driving force of 4.2 MPa, water conversion to hydrate for the experiments conducted with pure water was 72%, whereas for the experiments conducted with seawater, it was only 11.6%. While the role of salts as thermodynamic inhibitors is well-known, our study implies that, in the presence of porous media, the presence of salts significantly affects the kinetics of hydrate formation, resulting in a 6 time reduction in the conversion and also a significant reduction in the rate of hydrate formation. Subsequently, the hydrate samples were dissociated by employing thermal stimulation at a constant pressure of 4.8 MPa. Hydrates were thermally stimulated by two different driving forces (ΔT = 20 and 10) and the dissociation characteristics, and production rates were observed and determined. On the basis of the recovery curves obtained from all of the experiments conducted for water as well as seawater, we observed distinctive dissociation behaviors for the hydrates in seawater and hydrates in pure water.