Qun Zhang

As global warming intensifies, carbon dioxide (CO₂) has become one of the primary contributors to climate change. Carbon capture, utilization, and storage (CCUS) technology represents one of the most effective methods for reducing CO₂ emissions, offering a promising solution by capturing CO₂ and either utilizing it or storing it in underground reservoirs for long-term sequestration. Among various CCUS strategies, CO₂ geological utilization and storage (CGUS), which focuses on the geological aspects of CO₂ storage and its potential utilization, plays a pivotal role. However, existing CGUS technologies still face challenges, including high costs and low efficiency. To enhance CGUS efficiency, the development of innovative technologies and materials is essential for improving the overall capability of the processes. Nanomaterials are increasingly recognized as an ideal solution for enhancing CGUS technology due to their ultra-small size, high specific surface area, exceptional physical and chemical properties, and potential for functionalization. This review examines the latest advancements in the application of nanomaterials for CGUS, focusing on the characteristics and potential of metal oxide nanomaterials, carbon-based nanomaterials, and inorganic nanomaterials, particularly silicon dioxide (SiO₂). It also addresses the technical challenges that hinder the practical implementation of nanomaterials, including issues related to stability, scalable production, and environmental risks. Furthermore, the article outlines key research challenges and future directions for advancing CGUS technologies. The aim of this review is to provide a theoretical foundation and technical insights to drive innovation in CGUS technology.

This study addresses the limitations of traditional chemical flooding in low-permeability reservoirs by developing a nanofluid–surfactant binary flooding system (Has5/iNanoW1.0 binary flooding system) and investigating its microscopic mechanisms and enhanced oil recovery performance. The size of the nanofluid–surfactant binary flooding system reduces from 250 nm to 72 nm compared with pure surfactant; therefore it can enhance the ability to inject smaller pores. Core adsorption tests reveal that the addition of nanofluid can decrease surfactant adsorption by over 30%. The nanoscale synergistic effect of nanofluid (iNanoW1.0) and surfactant (Has5) and lower adsorption of surfactant allows more surfactant (Has5) to enter smaller pores for oil washing, significantly increasing oil recovery performance. Low-field nuclear magnetic resonance displacement experiments show that the binary system can significantly expand microscopic sweep efficiency (up to 14.9%) compared to pure surfactant or nanofluid flooding. Core flooding tests confirm that the binary system exhibits lower injection pressure (0.377 MPa), achieving 13.12% incremental oil recovery during post-water flooding, which is significantly better than the pure surfactant system (5.11%). The results demonstrate strong laboratory-scale potential and permit further pilot-scale evaluation.

This study investigates the application of nanofluid (iNanoW)–polymer binary flooding system to enhance oil recovery efficiency in medium-to-high permeability reservoirs. Traditional polymer flooding technologies still have the potential for further improvement in these types of reservoirs. Therefore, this study combines iNanoW with the polymer flooding system to examine its effects on the rheological properties, injectability, interfacial performance, sweep volume, and recovery factor of the polymer solution. Experimental results show that iNanoW significantly improves the injectability of the polymer solution. The introduction of iNanoW reduces the size of polymer aggregates, as demonstrated by aggregate size and rheological performance experiments. Power-law model analysis reveals that the flow behavior of the polymer solution is further improved with the introduction of iNanoW, manifested by weakened shear-thinning behavior, reduced viscosity, and optimized flowability, which in turn helps to improve oil recovery efficiency. Moreover, iNanoW interacts with polymer molecules, lowering the surface tension and enhancing wettability, thereby improving oil–water separation efficiency. Core flooding experiments show that the introduction of iNanoW significantly increases sweep volume, particularly in medium- and small-pore spaces, where oil recovery efficiencies reached 57.97% and 61.54%, respectively. These results indicate that iNanoW not only optimizes the rheological properties of the polymer solution but also improves fluid distribution during the flooding process, significantly enhancing the overall oil recovery performance. This study provides a new approach to optimizing polymer flooding technology and highlights the potential of iNanoW in improving oil recovery efficiency.

Alkyl sulfobetaine shows a strong advantage in the compounding of surfactants due to the defects in the size matching of hydrophilic and hydrophobic groups. The interfacial tensions (IFTs) of alkyl sulfobetaine (ASB) and xylene-substituted alkyl sulfobetaine (XSB) with oil-soluble (Span80) and water-soluble (Tween80) nonionic surfactants on a series of n-alkanes were studied using a spinning drop tensiometer to investigate the mechanism of IFT between nonionic and betaine surfactants. The two betaine surfactants’ IFTs are considerably impacted differently by Span80 and Tween80. The results demonstrate that Span80, through mixed adsorption with ASB and XSB, can create a relatively compacted interfacial film at the n-alkanes–water interface. The equilibrium IFT can be reduced to ultra-low values of 5.7 × 10⁻³ mN/m at ideal concentrations by tuning the fit between the size of the nonionic surfactant and the size of the oil-side vacancies of the betaine surfactant. Nevertheless, Tween80 has minimal effect on the IFT of betaine surfactants, and the betaine surfactant has no vacancies on the aqueous side. The present study provides significant research implications for screening betaine surfactants and their potential application in enhanced oil recovery (EOR) processes.

With the ongoing rise in global energy demand, the importance of enhanced oil recovery in oilfield development is becoming increasingly prominent. However, traditional chemical flooding agents face bottlenecks such as poor adaptability to application environments, unclear coupling mechanisms regarding multiple factors, as well as long research and development cycles. This paper systematically discusses the innovative paradigm of oilfield chemical agent development driven by artificial intelligence and proposes four core technological breakthroughs. Firstly, artificial intelligence-empowered molecular simulation technology can reveal the behavior mechanisms of flooding agents under extreme conditions. Secondly, intelligent molecular design using generative adversarial networks and reinforcement learning breaks through the traditional trial-and-error model. Thirdly, the construction of a data-mechanism dual-driven multi-objective optimization model achieves the collaborative prediction of physicochemical properties, economic benefits and environ mental friendliness. Lastly, an integrated system of robotic chemist and high-throughput experimental platforms forms a closed-loop system of “artificial intelligence design - automated synthesis- online detection”, yielding a complete ecosystem. The analysis of the current technological development challenges and future development directions reveals that the artificial intelligence-empowered intelligent Research and Development system is expected to promote the transformation of chemical flooding technology toward efficiency, environmental protection and sustainable development, providing a new standard for intelligent oil and gas field development. Document Type: Invited review Cited as: Wei, K., Zhou, M., Huang, J., Zhang, Q., Ding, B., Lyu, W., Peng, M. Chemical agents designed for oilfield development: A new paradigm empowered by artificial intelligence. Advances in Geo-Energy Research, 2025, 17(1): 1-16. https://doi.org/10.46690/ager.2025.07.01

As an efficient and economical method to enhance oil recovery (EOR), it is very important to explore the applicability of chemical flooding under harsh reservoir conditions, such as high temperature and high salinity. We designed microscopic visualization oil displacement experiments to comprehensively evaluate the oil displacement performance of the zwitterionic surfactant betaine (BSB), a temperature- and salinity-resistant hydrophobically modified polymer (BHR), and surfactant–polymer (SP) binary systems. Based on macroscopic properties and microscopic oil displacement effects, we confirmed that the BSB/BHR binary solution has the potential to synergistically improve oil displacement efficiency and quantified the reduction in residual oil and oil displacement efficiency within the swept range. The experimental results show that after water flooding, a large amount of residual oil remains in the porous media in the form of clusters, porous structures, and columnar formations. After water flooding, only slight emulsification occurred after the injection of BSB solution, and the residual oil could not be activated. The injection of polymer after water flooding can expand the swept range to a certain extent. However, the distribution of residual oil in the swept range is similar to that of water flooding, and the oil washing efficiency is low. The SP binary flooding process can expand sweep coverage and effectively decompose large oil clusters simultaneously. This enhances the oil washing efficiency within the swept area and can significantly improve oil recovery. Finally, we obtained the microscopic oil displacement mechanism of BSB/BHR binary system to synergistically increase the swept volume and effectively activate the residual oil after water flooding. It is the result of the combined action of low interfacial tension (IFT) and suitable bulk viscosity. These findings provide critical insights for optimizing chemical flooding strategies in high-temperature and high-salinity reservoirs, significantly advancing EOR applications in harsh environments.

In response to escalating global energy demand and climate change mitigation needs, natural gas hydrates (NGHs) are gaining prominence as a clean energy source. The CO₂ replacement method is an innovative NGH extraction technique that reduces reservoir risks and enables CO₂ sequestration. However, our understanding of the dynamics and control parameters in the hydrate replacement process is limited. This study pioneers a kinetic analysis and conceptual model for a CO₂-driven hydrate replacement, dividing the process into three spatial realms and sequential stages. We identify the optimal injection temperature range for standard NGH reservoirs and highlight the interplay between the gas injection rate and bottom-hole pressure on CH₄ yield. Our findings offer insights on how to optimize production efficiency and gas separation, advancing CO₂ replacement technology for NGHs.

CO₂-enhanced oil recovery (CO₂-EOR) is a crucial method for CO₂ utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO₂ and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO₂ utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO₂-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO₂-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO₂-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO₂-EOR techniques in heterogeneous and fractured reservoirs.