Jitendra Sangwai

The application of nanoparticles for enhanced oil recovery (EOR) has been shown to be advantageous over conventional methods. Wettability alteration of reservoir rock from oil-wet to water-wet is one of the main factors in improving oil recovery from matured reservoirs. The sandstone reservoirs are generally negatively charged, and hence, a proper selection of the surface charge of nanoparticles is important. In this work, a novel nanofluid is prepared using the synergistic effect of an oppositely charged Ludox CL silica nanoparticle (positive) and an anionic Aerosol-OT (AOT) surfactant in low-salinity seawater (LSW). The positively charged Ludox CL silica nanoparticle can readily adsorb on the Berea sandstone core due to electrostatic attraction, altering the wettability. The interfacial tension (IFT) and three-phase contact angle are measured to study the effect of the nanofluid on the IFT of the crude oil-nanofluid system and the wettability of the sandstone core. At a low AOT surfactant concentration, the nanoparticles are hydrophobic because of the monolayer adsorption of AOT with a higher tendency to sit at the oil-water interface, causing a reduction in the IFT. Moreover, scanning electron microscopy and energy-dispersive X-ray analyses were used to show the adsorption of nanoparticles on the Berea core surface and the desorption of crude oil from the core. The efficiency of different imbibition fluids was evaluated via a spontaneous imbibition technique using Amott cells. Experimental results showed that the oil recovery due to spontaneous imbibition of the nanofluid conducted on the Berea core yielded the highest oil recovery rate as compared to deionized water, LSW, pure silica nanoparticles, and a pure surfactant (AOT), respectively. The nanofluid showed excellent stability, significant wettability alteration, greater reduction of IFT, and great potential as an imbibition agent for EOR applications.

Stability of oil-in-water emulsions under high pressure and high temperature (HPHT) conditions has a significant interest in upstream oil and gas industrial applications. Such emulsions are generally stabilized with surfactants, which are thermodynamically unstable under HPHT conditions. Alternate to surfactants, the addition of nanoparticles has emerged as a method for emulsion stabilization, known as Pickering emulsion. In this work, a comparative study of the stability of silica nanoparticle (Ludox CL) stabilized Pickering emulsion against surfactant SDS (sodium dodecyl sulfate) stabilized emulsion under HPHT conditions has been explored. The stability of the emulsions was measured in terms of change in emulsion droplet diameter. Subsequently, emulsion samples are aged under different pressure and temperature conditions in an aging cell for 24 hours. The emulsion mean droplet diameter increases with an increase in temperature. The magnitude of change in the mean droplet diameter of aged SDS stabilized emulsion is higher as compared to Ludox CL stabilized emulsion under varying pressure (0.1–10 MPa) and temperature (303–363 K). It can be concluded that Ludox CL stabilized emulsion shows better stability as compared to SDS stabilized emulsion under HPHT conditions. Hence, emulsion stabilized by Ludox CL nanoparticle may withstand harsh reservoir conditions and can be used for enhanced oil recovery applications.

Microfluidics is a promising approach for investigating processes at the pore scale of rocks, such as oil recovery, due to their similar size range. Unlike conventional core flooding and Amott cell techniques, microfluidics offers advantages such as easy cleaning, reusing porous network chips, and the ability to track the process visually. In this study, a stable nanofluid (NF3) was prepared utilizing the synergistic effect of oppositely charged Ludox CL silica nanoparticles (positive charge) and anionic surfactant (Aerosol-OT) in 5000 ppm seawater. A microfluidic chip was used to assess the pore-scale oil displacement using different nanofluids. We visually investigated the efficacy of oil displacement from the chip, the interactions between pore grain-oil-nanofluids, and the wettability alteration of the pore grain surface. The results show that the interfacial tension (IFT) between the crude oil and the NF3 nanofluid showed a significant reduction in IFT by 49.3% compared to crude oil-seawater. The surfactant reduces the IFT between the crude oil and the nanofluid (thinning of the interfacial film), resulting in elongation of oil globules, and improves oil recovery. Furthermore, a thin layer of nanofluid film was observed between the pore grain surface and the fluid phase, visible as black curves, which might be the reason for the wettability alteration of the grain surface from oil-wet to water-wet, enhancing oil recovery. The cumulative oil displacement from the chip due to the NF3 nanofluid yielded the highest oil displacement efficiency of 88.85% of the original oil-in-place among all the injection fluids. In situ emulsification was observed in the pores of microfluidics due to the injection of the NF3 nanofluid, where the velocity gradient between the residual oil and the injected nanofluid causes some residual oil to be carried away as an emulsion, enhancing oil recovery. This study provides insights into the nanofluid, which can aid in IFT reduction, wettability alteration, better stability, and in situ emulsification, ultimately improving oil displacement through a porous medium.

Emulsions have a wide range of applications, and with the advancement in the use of nanoparticles to form stable Pickering emulsions, it is important to understand their rheological properties to infer their stability under high-pressure and high-temperature (HPHT) compared to the emulsion formed using conventional surfactants. In oil and gas production strategies, oil often forms an emulsion with brine either within reservoirs or at surface facilities in the presence of natural or artificial surfactants. Nanoparticles are also being explored to increase oil recovery from matured reservoirs. In various instances, stable emulsions are either formed in-situ (within the reservoir) or at surface facilities or injected into the reservoir to mobilize the trapped oil. It is also essential to understand their rheology for efficient oilfield application. This study investigates the impact of surface-modified silica nanoparticles (Ludox CL), NaCl salt, and surfactant on the stability of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure (0.1–10) MPa and high-temperature (303–363) K conditions. The viscosity of emulsion samples was measured at varying shear rates (0.1–1000) s−1. The viscoelastic behavior (G′, G″, η*, and δ) of the Pickering emulsion and surfactant-stabilized emulsion were also measured. The stability of the emulsions was measured in terms of changes in emulsion viscosity and droplet diameter. Both emulsions showed non-Newtonian shear thinning behavior and an increase in droplet diameter under HPHT conditions. However, the surfactant-stabilized emulsion exhibits a greater degree of change in emulsion viscosity and droplet diameter than the Pickering emulsion. It indicates that the Pickering emulsion showed better stability than the surfactant-stabilized emulsion under HPHT conditions. Hence, Pickering emulsions are an incredibly promising tool that might be employed in HPHT applications, especially for enhanced oil recovery applications, due to their better rheological stability.

The objective of this study is to develop a solvent-based Pickering emulsion stabilized by silica nanoparticle for enhanced heavy oil recovery. Unlike the light oil, the recovery of heavy oil is quite challenging because of its high viscosity. To reduce the viscosity of heavy crude oil, solvent-based Pickering emulsion is explored to improve the recovery of heavy oil. The approach is to use solvent-in-water emulsion stabilized by nanoparticle which is more economical as compared to thermal or solvent-based enhanced oil recovery (EOR) methods. In this work, the solvent-in-water Pickering emulsion has been prepared by homogenizing the mixture with the help of homogenizer at 13000 rpm for 3 minutes. It can be inferred from the experimental results that the use of nanoparticle has helped to improve the stability of solvent-based Pickering emulsion for a longer period of time as compared to conventional surfactant based emulsions due to irreversible adsorption of silica nanoparticle at the oil-water interface. The silica nanoparticle of 15 nm size is used to make the Pickering emulsion. The colloidal stability and surface charge of the nanoparticle is evaluated by zeta potential. Silica nanoparticle is expected to improve the rheological stability of solvent-based emulsion and provides favorable mobility. Hence, these solvent-based emulsion flooding can provide high displacement efficiencies like miscible solvent flooding and better sweep efficiency like polymer flooding and helps to improve the enhanced heavy oil recovery. The novelty of the nanoparticle stabilized solvent-based Pickering emulsion is that it can sustain harsh reservoir conditions and remains very stable for a longer period of time as compared to other EOR techniques. The droplet size of these emulsions is few micron in size so that it can easily flow through the pore throat size of the formation reservoir and helps in improving the enhanced heavy oil recovery.

This work reports an experimental and theoretical analysis of the rheological properties of mineral oil-based SiO2 nanofluid for their potential applications in transformer insulation. The flow electrification mechanism on the nanofluids with different surfactants such as cetyl trimethyl ammonium bromide (CTAB), oleic acid, and Span 80 is studied using a spinning disk technique. The results show a higher streaming current for the nanofluids with CTAB as a surfactant compared to oleic acid and Span 80. The rheological behavior of nanofluids is explored with the double gap concentric cylinder geometry. The variation of shear stress with shear rate follows a power law relationship along with a yield stress observed for all the nanofluids. A transition is seen from storage modulus to dominant loss modulus for the nanofluids during the frequency sweep analysis, whereas no transition is observed in the case of mineral oil. In addition, regression analysis using artificial neural network (ANN) algorithms are performed on the experimentally measured viscosity of the nanofluids in order to estimate theoretical parameters and provide insights into the streaming current formation. The desirable rheological characteristics of nanofluids are identified for achieving enhanced insulation performance in transformers.

Low salinity waterflooding (low salinity-EOR) has attracted great interest from many giant oil producers and is currently under trial in some of the oil fields of the United States, Middle Eastern countries, and North Sea reservoirs. Most of the reported studies on this process were carried out for medium to relatively heavy oil with significant polar contents. In this work, we have investigated low salinity waterflooding performance for light paraffinic crude oil with a low acid number. This study has been performed using crude oil from an Indian offshore oilfield and Indian offshore seawater. Oil recovery efficiencies of seawater and its diluted versions (low salinity seawater) were evaluated through core-flooding experiments performed on a silica sand pack containing small amounts (2 wt %) of bentonite clay saturated with crude oil. Interfacial tension and wettability studies were performed to understand the associated low salinity effects on the crude oil/brine/rock properties. Effluent brine produced during the flooding experiments was also analyzed to obtain a clearer insight into the low salinity-enhanced oil recovery (EOR) mechanism. The results showed that injection of low salinity seawater can significantly increase the waterflood recovery in comparison with high salinity seawater injection. Interfacial tension and contact angle studies revealed that there is an optimum dilution level at which the interfacial tension and wettability are the most favorable for enhanced oil recovery even in the case of light paraffinic crude. These results are in line with the results obtained from the core-flooding experiments. The possible reason behind recovery improvement based on the interfacial tension and wettability studies in conjugation with the effluent brine analysis has been discussed in detail. In this study, we have observed that the enhanced oil recovery efficiency could be achieved by applying low salinity seawater flooding even in the case of light paraffinic oil with a low acid number.

Interfacial tension (IFT) and wettability are the two major factors influencing oil recovery. The synergistic effect of low salinity water (LSW) with chemical agents such as surfactants, alkalis, and polymer is an emerging technology for enhanced oil recovery (EOR). Recently, the use of nanoparticles for EOR has become the attractive option. This study examines the impact of low salinity surfactant-silica nanofluid (LSS-SNF) on interfacial tension (IFT) and wettability alteration in an oil-water-quartz system using various types of oils, viz., n-heptane, n-decane, benzene, toluene, model oil A, model oil B, and crude oil. Besides, the adsorption of surfactants on the quartz substrate in the presence of silica nanoparticles is also studied. A quartz substrate is particularly chosen to mimic the sandstone formation. It has been observed that the type of oil has a crucial role in the IFT behavior, and different trends have been observed for model oil A and model oil B in the presence of LSS-SNF. Also, a prominent wettability shift is observed on the quartz substrate for the acidic (model oil A) than the other oil employed. Further, the adsorption studies using an ultraviolet-visible (UV-vis) spectrometer confirm the reduction in surfactant adsorption with an increase in silica nanoparticle concentration. The adsorption of surfactants is also confirmed using scanning electron microscopy (SEM) and energy-dispersive X-ray analysis (EDXA), and the order of adsorption is identical to the Freundlich adsorption isotherm. The outcomes of this study will help us understand the application of silica nanofluid in EOR operation.

Modern functional nanomaterials have tremendous scope in developing newer strategies for petroleum exploration, energy extraction, and oceanic sequestration. The functionalization of nanomaterials improves their tunability, effectiveness, and environmental susceptibility. Nanoparticle functionalization is done via simultaneous synthesis and functionalization strategies or post-synthesis functionalization. Nanoparticle inclusion in petroleum exploration reduces viscosity and interfacial tension, and enhances oil recovery from oil fields. Moreover, functional nanoparticles improve methane extraction from natural gas hydrate via the dissociation of hydrate cages. The current chapter discusses functional nanoparticle potential in petroleum exploration and process development, aiming to exploit the technology’s full potential in developing cost-effective strategies. Additionally, the chapter discusses nanoparticles’ role in enhanced oil recovery, wettability alteration, and interfacial tension reduction. This chapter also sheds light on methane extraction and oceanic CO2 sequestration through hydrates using nanomaterials.

Synergism between different enhanced oil recovery (EOR) methods has always been a subject of paramount interest for oil industry as it led to the development of many successful EOR methods in the past. Low salinity water flooding is a recent development in the field of EOR, and polymer flooding is a conventional EOR technique that has been practiced for many decades. In this study, we have investigated the synergistic effects of low salinity water flooding and polymer flooding focusing on the effect of low salinity on polymer rheology, polymer solution injectivity, retention of polymer in the reservoir rock, and oil recovery efficiency of low salinity polymer flooding. The study is comprised of a multidimensional experimental approach including measurements of bulk rheology of polymer solutions prepared with brines of varying salinities, single phase displacement experiments for injectivity analyses, UV-visible and electron dispersive spectroscopy along with scanning electron microscopy for studying retention of polymer on the reservoir rock surface, and finally laboratory flooding experiments to demonstrate the oil recovery efficiency of low salinity polymer flooding synergy. The results obtained from this study show that low salinity water tremendously improves the polymer rheology that could greatly favor the oil recovery efficiency of the overall process. Low salinity water is also found to be a very impressive agent for improving displacement efficacy and the injectivity of a polymer solution. Finally, the results of enhanced oil recovery flooding experiments demonstrated that low salinity polymer flooding could significantly increase the oil recovery efficiency in comparison to either low salinity or conventional polymer flooding alone.