The treatment of produced water is a major challenge faced by oil and gas industries worldwide. As a result of the increase in industrial activities, the generation of produced water has increased significantly. The most commonly used method for produced water oil–water separation is de-oiling hydrocyclone technology due to its simple construction, compact design, easy maintenance, and high efficiency. A wide breadth of scientific research studies has been carried out on performance evaluation, design optimisation, geometric parametrisation, external interventions, etc., to enhance the performance of hydrocyclones. These studies mostly rely on either experimental data obtained from the field, in laboratories under a controlled environment, or the application of numerical techniques for oil-in-water separation. Considering the extensive research studies published on hydrocyclone technology, this study aims to provide a comprehensive review of recent technological advancements in hydrocyclone technology in order to identify key areas where scientific research efforts should be concentrated. This will help make well-informed decisions for strategic investments in this wide area of research. Furthermore, it will widen the scope of applicability of hydrocyclones in the industrial sector.

Carbon capture and storage (CCS) is a critical technology for mitigating greenhouse gas emissions and combating climate change. CCS involves capturing CO₂ emissions from industrial processes and power plants and injecting them deep underground for long-term storage. The success of CCS projects is influenced by various factors, including the regional pressure dissipation effects in subsurface geological formations. The safe and efficient operation of CCS projects depends on maintaining the pressure in the storage formation. Regional pressure dissipation, often resulting from the permeability and geomechanical properties of the storage site, can have significant effects on project integrity. This paper provides a state-of-art of the impact of regional pressure dissipation on CCS projects, highlights its effects, and discusses ongoing investigations in this area based on different case studies. The results corroborate the idea that the Sleipner project has considerable lateral hydraulic connectivity, which is evidenced by pressure increase ranging from 1 MPa in case of substantial flow barriers. After five years of injection, pore pressures in the water leg of a gas reservoir have increased from 18 MPa to 30 MPa at Salah project, resulting in a 2 cm surface uplift. Furthermore, artificial CO₂ injection was simulated numerically for 30 years timespan in the depleted oil reservoir of Jurong, located near the Huangqiao CO₂-oil reservoir. The maximum amount of CO₂ injected into a single well could reach 5.43 × 10⁶ tons, potentially increasing the formation pressure by up to 9.5 MPa. In conclusion, regional pressure dissipation is a critical factor in the implementation of CCS projects. Its impact can affect project safety, efficiency, and environmental sustainability. Ongoing research and investigations are essential to improve our understanding of this phenomenon and develop strategies to mitigate its effects, ultimately advancing the success of CCS as a climate change mitigation solution.

>The majority of carbonate reservoirs have low porosity and permeability in general because of having a high amount of matrixes that make a...

Carbon dioxide (CO₂) geosequestration is a critical technology for reducing greenhouse gas emissions, with shale caprocks, such as Opalinus Clay (OPA), serving as essential seals to prevent CO₂ leakage. This study employs computational fluid dynamics and finite element analysis to investigate the hydromechanical behavior of OPA during CO₂ injection, integrating qualitative and quantitative insights. Validated numerical models indicate that capillary forces are the most critical factor in determining the material’s reaction, with an entry capillary pressure of 2–6 MPa serving as a significant threshold for CO₂ breakthrough. The numbers show that increasing the stress loading from 5 to 30 MPa lowers permeability by 0.3–0.45% for every 5 MPa increase. Porosity, on the other hand, drops by 9.2–9.4% under the same conditions. The OPA is compacted, and axial displacements confirm numerical models with an error margin of less than 10%. Saturation analysis demonstrates that CO₂ penetration becomes stronger at higher injection pressures (8–12 MPa), although capillary barriers slow migration until critical pressures are reached. These results demonstrate how OPA’s geomechanical stability and fluid dynamics interact, indicating that it may be utilized as a caprock for CO₂ storage. The study provides valuable insights for enhancing injection techniques and assessing the safety of long-term storage.

CO₂ geosequestration is an important contributor to United Nations Sustainable Development Goal 13, i.e., Climate Action, which states a global Net-Zero CO₂ emissions by 2050. A potential impact of CO₂ geosequestration in depleted oil and gas reservoirs is the variations in induced pressure across the caprocks, which can lead to significant local variations in CO₂ saturation. A detailed understanding of the relationship between the pressure gradient across the caprock and local CO₂ concentration is of utmost importance for assessing the potential of CO₂ geosequestration. Achieving this through experimental techniques is extremely difficult, and thus, we employ a coupled Computational Fluid Dynamics (CFD) and Finite Element Method (FEM) based solver to mimic sub-critical CO₂ injection in Opalinus Clay under various pressure gradients across the sample. The geomechanical and multiphase flow modelling utilising Darcy Law helps evaluate local variations in CO₂ concentration in Opalinus Clay. Well-validated numerical results indicate favourable sub-critical CO₂ geosequestration under a positive pressure gradient across Opalinus Clay. In the absence of a positive pressure gradient, a peak CO₂ concentration of 5% has been recorded, which increases substantially (above 90%) as the pressure gradient across the sample increases.