Effect of Titanium Dioxide Nanoparticles on Surfactants and Their Impact on the Interfacial Properties of the Oil-Water-Rock System

The application of nanoparticles (NPs) in the oil and gas industry has received wide attention in recent years because it is increasingly being considered a promising approach to recovering trapped oil in conventional hydrocarbon reservoirs. Numerous studies have demonstrated that combining nanoparticles with a surfactant can enhance surfactant performance by changing the interfacial properties of the solution when it comes in contact with crude oil and rock surfaces. However, more information and additional experimental data are required concerning the application of titanium dioxide nanoparticles in alkyl ethoxy carboxylic surfactants. In this study, we measure the changes in interfacial tension and wettability due to the addition of titanium dioxide nanoparticles (0, 100, 250, and 500 ppm) in alkyl ethoxy carboxylic surfactant using a spinning drop tensiometer and contact angle measurements. The interfacial tension of the crude oil-water (surfactant) system decreases by approximately two orders of magnitude with an increasing titanium dioxide concentration, exhibiting a minimum value of 5.85 × 10-5 mN/m. Similarly, the contact angle decreases on the surface of the Berea sandstone by combining the surfactant with titanium dioxide, reaching a minimum contact angle of 8.8°. These results demonstrate the potential of this new approach to maximize the recovery of trapped oil and significantly improve oil production.

Synthesis of Carboxyl Modified Polyether Polysiloxane Surfactant for the Biodegradable Foam Fire Extinguishing Agents

It is necessary to develop novel and efficient alternatives to fluorocarbon surfactant and prepare fluorine-free environmentally-friendly fire extinguishing agent. The carboxyl modified polyether polysiloxane surfactant (CMPS) with high surface activity was synthesized via the esterification reaction using hydroxyl-containing polyether modified polysiloxane (HPMS) and maleic anhydride (MA) as raw materials. The process conditions of the esterification reaction were optimized by orthogonal tests, and the optimum process parameters were determined as follows: reaction temperature of 85 °C, reaction time of 4.5 h, isopropyl alcohol content of 20% and the molar ratio of HPMS/MA of 1/1. The chemical structure, surface activity, aggregation behavior, foam properties, wetting properties and electron distribution were systematically investigated. It was found that the carboxyl group was successfully grafted into silicone molecule, and the conjugated system was formed, which changed the interaction force between the molecules and would affect the surface activity of the aqueous solution. The CMPS exhibited excellent surface activity and could effectively reduce the water's surface tension to 18.46 mN/m. The CMPS formed spherical aggregates in aqueous solution, and the contact angle value of CMPS is 15.56°, illustrating that CMPS had excellent hydrophilicity and wetting performance. The CMPS can enhance the foam property and has good stability. The electron distribution results indicate that the introduced carboxyl groups are more inclined towards the negative charge band, which would be conducive to weak the interaction between molecules and improve the surface activity of the solution. Consequently, new foam fire extinguishing agents were prepared by using CMPS as a key component and they exhibited excellent fire-fighting performance. The prepared CMPS would be the optimal alternative to fluorocarbon surfactant and could be applied in foam extinguishing agents.

Cardanol /SiO2 Nanocomposites for Inhibition of Formation Damage by Asphaltene Precipitation/Deposition in Light Crude Oil Reservoirs. Part II: Nanocomposite Evaluation and Coreflooding Test

This study aims to evaluate the behavior of Cardanol/SiO2 nanocomposites in the inhibition of the asphaltene damage based on the coreflooding test at reservoir conditions. The nanocomposite design was performed in Part I (https://doi.org/10.1021/acs.energyfuels.0c01114), leading to SiO2 nanoparticles functionalized with different mass fractions of cardanol on the surface of 5 (5CSN), 7 (7CSN), and 9% (9CSN). In this part of the study, the nanocomposite/reservoir fluid interactions were evaluated through interfacial tension measurements and nanocomposite/rock surface interactions using water imbibition and contact angle measurements. Results showed that the designed nanocomposite leads to a reduction of interfacial tension of 82.6, 61.7, and 51.4% for 5CSN, 7CSN, and 9CSN regarding silica support (SN). Whereas, the reduction of the Si-OH functional groups from SiO2 nanoparticles due to the increase of the cardanol content affects the effectiveness of the wettability alteration for 7CSN and 9CSN. Nevertheless, when 5CSN is evaluated, the system is altered from an oil-wet to a mixed-wet state. Coreflooding tests at reservoir conditions were performed to evaluate the oil recovery after asphaltene damage, after damage removal and nanofluid injection, and after induction of a second asphaltene damage to check inhibition. Results show that the selected nanocomposites at a dosage of 300 mg·L-1 enhance the oil recovery in comparison with the baseline conditions via the reduction of the interfacial/surface forces at the pore scale and wettability alteration. It is worth to remark that this improvement remains after the second asphaltene damage induction, which proves the high inhibitory capacity of the designed nanocomposite for the asphaltene precipitation/deposition. Also, the use of the nanocomposites favors the oil recovery more than 50% compared to the asphaltene damage scenario.

Interaction of low salinity surfactant nanofluids with carbonate surfaces and molecular level dynamics at fluid-fluid interface at ScCO2 loading

HYPOTHESIS

The advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and CO₂ geosequestration. Interaction of various ionic species present in the novel low salinity surfactant nanofluids with scCO₂/CO₂ saturated aqueous phase interface and at the interface of CO₂ saturated aqueous phase/mixed wet (with CO₂ and Decane) limestone surface at the conditions of low salinity at reservoir conditions are to yet to be understood.

EXPERIMENTS

This study, carried out for the first time in low salinity at scCO₂ loading conditions at 20 MPa pressure and 343 K temperature, comprises of wettability study of the limestone surface by aqueous phase contact angle measurements using ZrO₂ nanoparticles (in the concentration range of 100-2000 mg/L) and 0.82 mM Hexadecyltrimethylammonium bromide (CTAB) surfactant. Molecular dynamics simulations results were used to understand the underlying mechanism of wettability alteration and interfacial tension (IFT) change.

FINDINGS

This study reveals that a low dosage (100 mg/L) of ZrO₂ nanoparticles forming ZrO₂-CTAB nano-complexes helps in wettability alteration of the rock surface to more water-wetting state; certain ionic species augment this effect when used in appropriate concentration. Also, these nano-complexes helps in scCO₂/CO₂ saturated aqueous phase IFT reduction. This study can be used to design advanced low salinity injection fluids for water alternating gas injection for EOR and CO₂ geosequestration projects.

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

HYPOTHESIS

Nanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO₂-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO₂-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO₂ geo-storage.

EXPERIMENTS

Pendant drop method was used to measure CO₂/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell.

FINDINGS

CO₂/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO₂/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO₂/nanofluid γ. Hence, CO₂/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO₂ storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid. The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects.