Jitendra Sangwai

Drilling fluid is one of the most important components of drilling operation in oil and gas, mining and geothermal industries. Nanotechnology can be used to develop drilling fluid additives that can improve the drilling fluid properties. In this work, the feasibility of using two types of nanoparticle additives in water-based drilling fluid has been investigated. Clay/SiO2 nanocomposite was synthesized (by effective hydrothermal method) and successfully characterised. A series of experiments are performed to evaluate the effect of SiO2 and clay nanoparticles on the rheological and filtration properties of water-base drilling fluids. The experiments are conducted at different concentrations of Clay/SiO2 and SiO2 nanoparticles, and also at a range of temperatures. The results showed that the addition of clay and SiO2 nanoparticles improved the rheological and fluid loss properties. It was also noticed that the nanoparticles provide thermal stability to the drilling fluid. The experimental results suggest that the Clay/SiO2 nanoparticles have a more significant impact on the rheological and fluid loss properties of the drilling fluid comparing to SiO2 nanoparticles, particularly at higher temperatures.

Nanotechnology provides promising possibilities for various oilfield applications in the upstream oil and gas industry. Nanofluids play a vital role in the development of newer technologies suitable for industrial applications and can be explored for use in the upstream petroleum industry. One of the commonly used biopolymers, xanthan gum (XG), is used in the upstream oil and gas industry as a rheological modifier, drilling fluid additive, emulsion stabilizer, and fluid loss controlling agent. Consequently, its use can be studied for the preparation of nanofluids, an application not reported in literature. In this study, zinc oxide (ZnO) and copper oxide (CuO) nanofluids, with varying concentrations of nanoparticles (0.1, 0.3, and 0.5. wt.%), were prepared using the two-step method in a 0.4. wt.% XG (as a dispersant) aqueous solution as a base. These CuO and ZnO nanofluids were characterized for stability and dispersion using a scanning electron microscope (SEM) and the dynamic light scattering (DLS) method, respectively. It is observed that the CuO nanofluid in XG aqueous solution is more stable than the ZnO nanofluid. XG was observed to form a jelly-like structure around the nanoparticles, keeping them suspended in the solution. This paper investigates and presents the thermal conductivity and electrical conductivity of these nanofluids. The results show that thermal and electrical conductivity are enhanced as the concentration of nanoparticles was increased. The thermal and electrical conductivity was observed to be enhanced by approximately 25 and 50% for ZnO and CuO nanofluid, respectively. This study is expected to form the basis for the development of nanofluid-based technologies with XG as the primary additive in the upstream oil and gas industry. © 2013 Elsevier B.V.

Information on the viscosity of Pickering emulsion is required for their successful application in upstream oil and gas industry to understand their stability at extreme environment. In this work, anovel formulation of oil-in-water (o/w) Pickering emulsion stabilized using nanoparticle-surfactant-polymer (polyacrylamide) system as formulated in our earlier work (Sharma et al., Journal of Industrial and Engineering Chemistry, 2014) is investigated for rheological stability at high pressure and high temperature (HPHT) conditions using a controlled-strain rheometer. The nanoparticle (SiO2and clay) concentration is varied from 1.0 to 5.0 wt%. The results are compared with the rheological behavior of simple o/w emulsion stabilized by surfactant-polymer system. Both the emulsions exhibit non-Newtonian shear thinning behavior. A positive shift in this behavior is observed for surfactant-polymer stabilized emulsion at high pressure conditions. Yield stress is observed to increase with pressure for surfactant-polymer emulsion. In addition, increase in temperature has an adverse effect on the viscosity of emulsion stabilized by surfactant-polymer system. In case of nanoparticle-surfactant-polymer stabilized o/w emulsion system, the viscosity and yield stress are predominantly constant for varying pressure and temperature conditions. The viscosity data for both o/w emulsion systems are fitted by the Herschel-Bulkley model and found to be satisfactory. In general, the study indicates that the Pickering emulsion stabilized by nanoparticle-surfactant-polymer system shows improved and stable rheological properties as compared to conventional emulsion stabilized by surfactant-polymer system indicating their successful application for HPHT environment in upstream oil and gas industry.

Pickering emulsion offers potential applications in several fields including oil and gas industry due to their enhanced stability. Oil-in-water (o/w) emulsions are usually stabilized by surfactant or nanoparticle or by both but show poor thermal stability which limits their use for high-temperature applications. In this work, a novel formulation of o/w emulsion stabilized using nanoparticle-surfactant-polymer system is investigated for the formulation of thermally stable Pickering emulsion. The conventional oilfield polymer polyacrylamide (PAM), surfactant, sodium dodecylsulfate (SDS), and nanoparticles such as, SiO2, clay, and CuO in varying concentration are used. It is observed that the nanoparticle in the presence of surfactant and polymer synergistically interacted at the oil-water interface. The effect of temperature, pH, and salinity on the interfacial tension is investigated to understand the thermal stability. The emulsion system with partially hydrophobic clay nanoparticles in the presence of PAM and SDS shows higher thermal stability as compared to fully hydrophilic SiO2 nanoparticles. In the presence of salt, NaCl (1.0wt%), the thermal stability of clay and SiO2 stabilized emulsions is observed to be further promoted at higher temperatures. Scanning electron microscopy (SEM) images confirm the existence of a structured and rigid layer of nanoparticle at the oil-water interface.

The reduction in interfacial tension (IFT) of paraffin crude oil is of key importance, particularly for oilfield applications such as enhanced oil recovery (EOR). Nanoparticle laden suspension such as nanofluid is gaining widespread interest and their use to achieve moderate IFT reduction in paraffin crude oil. In this work, stable nanofluids of an oilfield polymer (polyacrylamide, PAM) with and without surfactant (sodium dodecyl sulfate, SDS) have been formulated and examined for IFT reduction of paraffin oils such as n-decane, n-hexane, n-pentane, and n-heptane. Nanofluids were also investigated for various studies such as dispersion stability, viscosity, rate of sedimentation (ROS), and DLS based measurements (size and zeta-potential). Other studies involving investigations on surface tension (SFT), IFT reduction, effect of SDS and varying SiO2concentration on IFT reduction, and their efficacy for IFT reduction under high temperature environment have also been reported. The performance of nanofluids for IFT reduction has been compared with IFT results of conventional polymer (P) and surfactant-polymer (SP) methods, which are typically used for chemical-EOR practices. As compared to P and SP methods, IFT value of nanoparticle-polymer (NP) and nanoparticle-surfactant-polymer (NSP) fluids were found to be significantly lower suitable for enhanced oil recovery. In addition, NSP nanofluids provided superior reduction in IFT values mainly due to the presence of SDS. Thus, we conclude that SiO2nanofluid, as compared to P/SP EOR methods, can be a potential alternative to reduce the IFT of paraffin crude oil.

Nanotechnology offers potential benefits for improving the next-generation enhanced oil recovery (EOR) process from Brownfield reservoirs. In our recent study (Sharma et al., 2014a), we formulated novel Pickering emulsion stabilized using conventional oilfield polymer polyacrylamide (PAM) and nanoparticles (SiO2 and clay) in the presence of surfactant, which is thermally stable at elevated temperature and suitable for EOR application. In this study, the use of these Pickering emulsion is investigated for enhanced oil recovery. Two types of flood systems, viz., surfactant-polymer (SP) and o/w Pickering emulsion flood, are prepared and used for 12 core flooding experiments to study the additional oil recovery at reservoir pressure of 13.6MPa and temperature ranges from 313 to 363K. These reservoir conditions of pressure and temperature are representative to one of the mature reservoirs in India. The incorporation of nanoparticle was observed to provide relatively lower and stable interfacial tension (IFT) for the Pickering emulsion. The viscosity of SP system was observed to decrease with temperature (313-363K), while that of Pickering emulsion was observed to remain stable and thereby indicating a possible stable mobility ratio downhole during EOR. Nanoparticle stabilized Pickering emulsion observed to give enhanced oil recovery by about 80% more at elevated temperatures as compared to conventional SP flood, showing promising advantages of employment of nanoparticles in oilfield industry. The investigation on the permeability reduction indicated a relatively larger retention of SiO2 nanoparticle than its counterpart clay, which is attributed to its larger size in the system.

Efficient flooding agents are required to produce additional oil from mature reservoir. In this work, oil-in-water Pickering emulsion systems stabilized using nanoparticles, surfactant, and polymer have been developed and tested for enhanced oil recovery with and without a conventional polymer flood. Stability of nanoparticles in the dispersion of surfactant-polymer solution was tested using zeta-potential before use. Several flooding experiments have been conducted using Berea core samples at 13.6 MPa and temperatures of 313 and 353 K. It has been observed that a combination of 0.5 PV polymer flood with 0.5 PV Pickering emulsion was efficient and have resulted in 1-6% additional oil recovery as compared to 0.5 PV Pickering emulsion flooding alone. The injection of polymer flood have shown to enhance the pressure drop in the core sample after emulsion flooding and considered as an important factor for an additional recovery of oil. The effect of temperature on the viscosity of flooding agents in relation to pressure drop and oil recovery have also been investigated. Viscosity and pressure drop of emulsion flood systems have shown to marginally decrease with increase in temperature. Studies on nanoparticle retention using SEM have shown that nanoparticles were retained in the core sample during emulsion flooding which may be detrimental for permeability of core sample. It is observed that Pickering emulsion flood with polymer flood would be effective for the enhanced oil recovery suitable for matured reservoirs.