During petroleum production, flow assurance becomes a critical concern when asphaltene precipitation (AP) and deposition (AD) occur. Researchers have recently turned their attention to nanotechnology as a means to prevent and repair damage caused by AP and AD. This study introduces an effective inhibitor named GONEDA (graphene-oxide-N(1-naphthyl)-ethylenediamine) for asphaltene precipitation. The synthesis of functionalized nanoparticle was carried out using Hummer's technique. Subsequently, the synthesized nanoparticle was characterized through various experiments including x-ray diffraction, transmission electron microscopy, field emission-scanning electron microscopy, Fourier-transform infrared spectroscopy, dynamic light scattering, and Brunauer–Emmett–Teller analyses. These experiments have confirmed GONEDA's unique structural properties, such as large surface area, which enhance its ability to adsorb asphaltene molecules. Batch adsorption tests were conducted to measure the adsorption capacity and efficiency of nanoparticles toward asphaltene molecules. Additionally, the indirect method was employed to detect the onset point of AP and quantify the amount of precipitated asphaltene based on differences in the optical properties of the supernatant fluid. Findings indicate that increasing the concentration of GONEDA nanoparticles leads to a decrease in their capacity but an increase in efficiency. The abundance of oxygen atoms within the GONEDA structure allows preferential adsorption of asphaltene molecules, resulting in a favorable effect on delaying AP. Specifically, compared to reference synthetic oils, the newly developed nanoparticles delayed the onset of AP by approximately 26%, 20%, and 8% for the oils containing 1000, 3000, and 5000 ppm of asphaltene, respectively. Furthermore, the presence of GONEDA NPs decreased the amount of precipitated asphaltene. These results demonstrate significant potential for field-testing, despite the laboratory-scale nature of the experiments.

The chemical and mechanical interactions between fluids and rocks, impairing the permeability and porosity of the reservoir, can lead to operational and economic challenges. These interactions can have a negative impact on the mechanical virtues of the rock, ultimately altering the petrophysical characteristics of the rock. The interactions cause alterations in the geometry of the pore space and the strength of the rock. Therefore, it is crucial to assess these variables before designing any oil recovery and gas storage project. The rock properties, particularly strength, permeability, and porosity, are changed during various stages such as drilling, production, and the injection of water or chemicals. In this regard, this research presents an examination review of the impact of fluid-rock interactions on the mechanical attributes of the formation rock, specifically focusing on the occurrence of formation damage. Generally, it is crucial to possess a strong comprehension of the interactions between fluids and rocks, as well as their effects on mechanical attributes and formation damage. This manuscript compiles recent studies to study the effect of interactions on rock petrophysical properties as well as mechanical properties, and in this regard, provides new perspectives on fluid-rock interactions in reservoirs. This understanding is vital in order to minimize both economic losses and technical complexities. Also, this manuscript can help researchers gain a complete perspective on the effect of fluids on rock mechanical properties in storage operations.

Injecting CO ₂ into water-disposal wells is a promising strategy for geological carbon storage. However, this process can destabilize asphaltenes in residual oil blobs—primarily of the emulsified type – trapped within trapped in the porous rock, leading to precipitation that threatens storage integrity and operational safety. This study introduces a novel high-pressure laboratory apparatus and protocol designed to directly quantify asphaltene precipitation during CO ₂ injection into oil-in-water emulsions, which represent water-flooded formations. The system operates at reservoir-relevant conditions (up to 11,000 psi and 210 °C) and utilizes in situ near-infrared (NIR) light transmission to monitor asphaltene precipitation in real-time. Additionally, this research investigates the behavior of the oil-in-water emulsion (EM) phase as the medium hosting CO ₂ gas under different conditions. Quantitative results, expressed as the percentage reduction in NIR transmission, showed that asphaltene precipitation was minimized to 0.8% under optimal conditions (2DSW, 120 °C, 50 mol% CO ₂ ), compared to a peak of 25.1% in the worst-case scenario (FW, 30 °C, 35 mol% CO ₂ ). Regarding the CO ₂ injection rate, less asphaltene precipitation occurred at higher injection rates. In this case, crude oil vaporized in the EM phase at high CO ₂ injection rates (above 35 mol%), resulting in fewer crude oil droplets available to interact with CO ₂ . Notably, EMs prepared with twice-diluted seawater (2DSW) exhibited the least asphaltene precipitation, a finding strongly correlated with lower oil/water interfacial tension. Overall, the developed protocol provides a critical tool for screening and de-risking CO ₂ storage sites in water-disposal zones by enabling accurate prediction of asphaltene-related damage.

This study presents a novel approach for enhanced oil recovery (EOR) in carbonate reservoirs through the synergistic use of engineered low-salinity brine and nanoparticles. Generally, conventional studies of nanofluid-EOR in carbonates largely focus on the macroscopic effects of metal oxides, leaving the design and behavior of custom multi-component nanofluids engineered to control multiple interfacial forces simultaneously poorly understood. In this study, the nanoparticle was synthesized by functionalization with other chemicals (potassium laurate and Triton X-100). The results showed that excellent colloidal stability, evidenced by a zeta potential of -58.46 mV at 80 ppm and pH 4.5. Also, contact angle analysis demonstrated a wettability shift from oil-wet to strongly water-wet. Core flooding tests achieved a significant incremental oil recovery of 31.11%, driven by the synergistic reduction of interfacial tension, effective wettability alteration, and enhanced structural disjoining pressure. The results identify the optimal and cost-effective nanofluid concentrations (80 ppm) for field-scale injection into carbonate reservoirs. These findings underscore the promise of engineered nanofluid brine systems as a viable and sustainable EOR strategy, providing valuable direction for the development of advanced materials in energy and industrial applications.