Abstract

Carbon capture, utilization and storage (CCUS) technology is currently the most promising method for achieving low-carbon development and carbon reduction. The carbon storage and utilization part involves the injection of CO2 into the underground. However, due to the low density and low viscosity of CO2, gas migration often occurs during the migration of CO2 in the formation, so suitable sealing agents are needed to repair the leakage of CO2. A composite gel system for inhibiting CO2 leakage was developed using the one-pot method. In this system, diethylenetriamine acts as the CO2-responsive molecule, forming CO2-responsive worm-like micelles with long-chain anionic surfactants. Acrylamide and a high-temperature crosslinking agent form temperature-responsive underground crosslinked gels. The response mechanism of the CO2-responsive worm-like micelles to CO2 is that the DETA molecules in the system come into contact with CO2 and undergo protonation. The protonated DETA then attracts the anionic surfactant head groups through electrostatic interactions, forming a “pseudo-dipole” surfactant, and subsequently self-assembles to form worm-like micelles. When in contact with CO2, the viscosity of these micelles will increase sharply, thus solving the problem of CO2 channeling. The composite gel undergoes a cross-linking reaction at temperatures above 125℃, forming a non-flowing gel. This gel has excellent temperature resistance and mainly seals the weakly acidic fluid resulting from the dissolution of CO2 in water. The research results show that during the alternating introduction of CO2/N2, the CO2-responsive worm-like micelles can switch between low and high viscosities, and the CO2 gas sealing rate can reach 99.61%. The composite gel can remain stable for 360 days at 140℃, and the water injection sealing rate can reach 98.92%. This dual-response composite gel system based on CO2 and temperature provides technical support for CO2 sequestration and utilization, and has broad application prospects for restraining CO2 channeling.

Abstract

Carbon dioxide (CO₂) flooding, a critical enhanced oil recovery (EOR) technique, exhibits unresolved miscibility mechanisms and dynamic processes. This study systematically investigates the property evolution of formation fluids and miscibility behavior post-CO₂ injection through comprehensive physical visualization characterization and experiments. Results demonstrate that CO₂ injection markedly reduces fluid density and viscosity, elevates saturation pressure, and induces exponential growth in volumetric expansion coefficients. Concurrently, the phase envelope shifts leftward and upward with expansion of the two-phase region during miscible displacement, while critical parameters undergo dynamic adjustments contingent upon dissolution ratios. Visualization experiments delineate the miscibility process into three mechanistic stages: swelling, mass-transfer zone transition, and miscibility achievement-each exhibiting distinct characteristics. These findings advance fundamental understanding of CO₂ flooding mechanisms and provide a theoretical framework for optimizing field implementation.

Abstract

Low salinity carbonated water flooding (LSCWF) combines the advantages of low salinity water flooding (LSWF) and carbonated water flooding (CWF). It is considered as one of the most promising CO₂-Enhanced Oil Recovery (CO₂-EOR) methods with effectively achieving carbon sequestration. However, the mechanism of LSCWF enhancing oil recovery at the pore scale remains unclear, which hinders the development and application of this technology.To bridge the gaps, this work developed a mathematical model that couples the Navier-Stokes equation, the phase field method equation, and the convection-diffusion equation to study the microscopic mechanism of low salinity carbonated water displacing oil. The dynamic distribution patterns of oil and water of LSCWF in the porous media were analyzed and compared with water flooding (WF) and LSWF. The microscopic oil recovery enhancement mechanism of low salinity carbonated water in different types of channels is emphatically analyzed, and a parameter sensitivity analysis is carried out.The results show that when the recovery factor of LSCWF reaches 81.83% after 10 PV displacement, which is significantly better than that of water flooding (61.57%) and low salinity water flooding (67.02%). Microscopic analysis reveals that this is mainly attributed to the remarkable increase in the recovery of blind ends, main channels, and cluster regions by low salinity carbonated water. The key microscopic mechanisms involve the mass transfer of CO₂ from carbonated water into the oil phase, which reduces oil viscosity at the fluid interface, improves the oil-water mobility ratio, and significantly enhances water-phase scouring efficiency. And LSCWF can also significantly decrease the seepage resistance, and strip out more residual oil. This study reveals the pore scale microscopic mechanism of LSCWF for EOR, supporting efficient complex reservoir development and the “dual carbon” goal.

Abstract

COâ‚‚/Hâ‚‚ underground bio-methanation (UBM) technology offers considerable promise because of its versatile functions. However, alongside biocatalysts methanogens, sulfate-reducing bacteria (SRB) and acetogens also utilize CO₂ / H₂ as substrates, initiating a range of complex geochemical reactions that may impact both the efficiency and safety of the process. To elucidate the complex biochemical and geochemical interplay in UBM, this study utilized an innovative microbial kinetic model that incorporates environmental factors and subsurface space limitations, implemented within the geochemical simulation platform PHREEQC. This framework facilitated the analysis of scenarios where methanogens, acetogens, and SRB exist individually within different mineral systems, enhancing understanding of each microbe’s influence. Building on this, the study further examined complex interactions when all three microbes are present together, as well as the effects of reservoir temperature and gas pressure. The results indicate that both methanogen and SRB metabolism tend to raise the pH of formation water, while acetogen metabolism has the opposite effect. When all three microbes are present, the buffering effect of carbonate minerals enhances methanogen activity, causing a rise in pH during CO₂ /H₂ conversion, which leads to the re-dissolution of hydrogen sulfide gas produced by SRB into the formation water, thereby reducing safety risks. Ultimately, CH4 makes up as much as 96% of the gas phase. Additionally, when the temperature is near the optimal growth range for methanogens, the conversion rate is rapid; however, the competitive consumption of CO₂ and H₂ by acetogens also intensifies. Moreover, an increase in the total pressure of CO₂ and H₂ results in a lower pH in the formation water. This shift suppresses methanogen function, lowering the conversion efficiency and causing a greater proportion of CO₂ and H₂ to be transformed into acetate. The findings of this study contribute to understanding the complex biochemical and geochemical interplay in UBM and provide guidance for selecting sites and optimizing design in UBM projects.

Abstract

CO2 geological sequestration has been widely adopted as a key strategy for mitigating greenhouse-gas emissions and addressing climate change. Previous simulation techniques typically coupled thermal, hydraulic, mechanical and chemical (THMC) processes, yet they often omit the fracture initiation and evolution mechanisms induced by high injection pressures and temperature gradients. In this study, a novel numerical framework is introduced to simulate fracture initiation and extension during CO2 storage. This method integrates the thermal, hydraulic, mechanical and chemical reaction (THMC) processes with dynamic fracture generation and propagation to enable accurate prediction of caprock integrity and long-term storage safety. The proposed numerical framework extended the Embedded Discrete Fracture Modeling (EDFM) to fracture initiation and extension based on tension and shear failure criteria, and dynamically updates the hydraulic properties of fractures throughout the simulation. Meanwhile, heat transfer between the injected CO2 and the reservoir, stress redistribution, and relevant geochemical reactions are fully coupled to assess the impacts of fracture evolution on multi-field dynamics. The proposed framework was demonstrated using a two-dimensional In Salah CO2 storage model. The results indicated that fractures first initiated around the CO2 injection well after approximately 5 years of injection, and then extended along the caprock-saline aquifer interface. In addition, it is observed that fracture evolution exerted a pronounced influence on surface deformation. The proposed framework provides a rigorous, quantitative tool for fracture evolution forecast and containment risk management in CO2 storage projects.