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Water-based fracturing fluids without an inhibitor promote clay swelling, which eventually creates wellbore instability. Several ionic liquids (ILs) have been studied as swelling inhibitors in recent years. The cations of the ILs are crucial to the inhibitory mechanisms that take place during hydraulic fracturing. Individual studies were carried out on several ILs with various cations, with the most frequently found being ammonium and imidazolium cations. As a result, the goal of this study is to compare these two cations to find an effective swelling inhibitor. A comparison and evaluation of the clay swelling inhibitory properties of tetramethylammonium chloride (TMACl) and 1-ethyl-3-methylimidazolium chloride (EMIMCl) were conducted in this work. Their results were also compared to a conventional inhibitor, potassium chloride (KCl), to see which performed better. The linear swelling test and the rheology test were used to determine the inhibitory performance of these compounds. Zeta potential measurements, Fourier-transform infrared spectroscopy, and contact angle measurements were carried out to experimentally explain the inhibitory mechanisms. In addition, the COSMO-RS simulation was conducted to explain the inhibitory processes and provide support for the experimental findings. The findings of the linear swelling test revealed that the swelling was reduced by 23.40% and 15.66%, respectively, after the application of TMACl and EMIMCl. The adsorption of ILs on the negatively charged clay surfaces, neutralizing the charges, as well as the lowering of the surface hydrophilicity, aided in the improvement of the swelling inhibition performance.

Scale formation is one of the major issues in the petroleum industry. The development of these scale layers could result in production losses and equipment instability because of pipeline blockage, energy leakage, corrosion acceleration and severe accidents which will impact the safety of the production process. The utilization of chemical scale inhibitors (SIs) is considered an economical and successful route for the scale prevention. Two main components of the chemical SIs are phosphonate and polymer. Many of the phosphorous compounds are toxic and very expensive. Besides, portions of the phosphonate compounds are thermally less stable than polymeric scale inhibitors in a harsh environment of high temperature and high pressure (HTHP). This is considered as an issue as a good scale inhibitor should be able to be applied under wide range of temperature and pressure. Therefore, the continuous development in petroleum production imposes the need to develop a novel phosphorus-free scale inhibitor. Meanwhile, polymers have been broadly applied as a scale inhibitor in oil and gas fields because of their enhanced thermal stability and improved environmental compatibility. Polymeric scale inhibitors also show better dispersing efficiency. Today, the biopolymers have pulled in a tremendous consideration from the industry to replace the utilization of synthetic polymer due to their interesting qualities such as their lightness, strong mechanical properties, and appealing functionality. Biopolymers are insensitive toward brine salinity yet are vulnerable to biological degradation. Specifically, these polymers present enormous potential for environmental application because of their biodegradability, chemical adaptability and reactivity, biocompatibility, and nontoxicity. Recently, several new eco-friendly scale inhibitors have been reported in the literature. Hence, this paper provides a review of the utilization of biopolymer as scale inhibitor in the application of oil and gas industry under laboratory approach or field trial application. The types of scales, chemical scale inhibitors (SIs) and biopolymers are likewise reviewed here. The presented work in this paper is expected to enhance the fundamental understanding of scale formation, as well as contribute to the development process of biopolymer scale inhibitors.

Surfactants have the ability to overcome the capillary forces restricting mobilization of oil in the porous media. Generally, the application of surfactants in harsh reservoir conditions has been avoided, due to the challenges accompanying their implementation in such conditions. In this paper, the performance of a mixture of Alkyl Ether Carboxylate (AEC) and Alkylpolyglucoside (APG) was experimentally investigated in harsh reservoir conditions. A Malaysian offshore field with challenging conditions has been studied in this present work, with a reservoir temperature of 106°C and injection water salinity of 32,000 ppm. The investigations were made using surface tension, interfacial tension and partitioning experiments. Surfactant concentration was measured throughout the partitioning test using High Performance Liquid Chromatography (HPLC). The results of the surface tension test showed that the CMC for AEC:APG mixture was approximately 0.13 wt% at 106 °C. IFT results showed that the presence of the surfactant mixture was capable of reducing the IFT between crude oil and brine, and achieve low IFT value (0.035 mN/m) in such harsh conditions. Partitioning test results explained the partitioning behaviour of the surfactant molecules into the oil-water interface. Additionally, surfactant concentration, brine/oil ratio and salinity have a significant impact on surfactant partitioning. The results corresponded to the interfacial tension behaviour, where the lowest IFT value was observed at the highest kp value for the AEC:APG mixture. This concluded that the partitioning coefficient can be directly related to interfacial tension. Furthermore, the increase of the brine/oil ratio as well as the salinity, portrayed an increasing trend of the kp values. The findings of this study showed promising outcomes for future implementation of surfactant flooding in such harsh conditions. By using the proposed surfactant mixture, potential success becomes likely for surfactant flooding application in this study under harsh reservoir conditions.