Abstract

The solubility of CO2 under ocean storage conditions affects the dissolution rate and dissolution amount of CO2 in seawater, and then affects the final storage amount. In this study, the solubility of CO2 in actual seawater was studied by a combination of experiments and models. Firstly, based on the literature data, the model of carbon dioxide solubility in pure water was constructed, and the AAD was 2.2%. Then, a solubility measurement system based on Raman spectrometer was built, and the quantitative relationship between peak intensity ratio and solubility S=HR/0.20225 was established by solubility method, and the solubility of CO2 in the actual seawater in the range of 276.15-286.65 K and 2-20 MPa was further measured by using this quantitative relationship, and the measurement results showed that the sensitivity of CO2 solubility in seawater to seawater depth was significantly reduced after the storage depth of 400m. Finally, the obtained experimental data was coupled with the model, and the AAD was 2.8%.

Abstract

This paper focuses on the importance of carbon dioxide capture, displacement and storage (CCUS-EOR) and the production stability problems of the gathering and transportation system. Based on the analysis of typical practices at home and abroad, combined with the actual situation of North China Oilfield, this paper proposes the experience and practice of production stability guarantee measures for the CO2 flooding gathering and transportation system in North China Oilfield, aiming to further improve the application effect of CO2 flooding process in North China Oilfield and the safety, stability and flexibility of production and operation.

Abstract

In CO2 enhanced oil recovery (EOR) and sequestration operations, the temperature and pressure of bottomhole fluids play a crucial role in determining CO2’s oil solubility and mobility. To achieve optimal EOR and sequestration results, it is essential to design parameters such as injection temperature, pressure, wellbore structure, and insulation materials. To address the issues in designing CCUS injection parameters, this paper proposes a multi-objective intelligent optimization method for CCUS injection parameters based on an improved second-generation Non-dominated Sorting Genetic Algorithm (NSGA-II). First, a CO2 injection wellbore temperature and pressure calculation model is constructed, enabling the characterization of fluid flow along the wellbore and the simulation of bottomhole temperature and pressure. Subsequently, by introducing an Estimation of Distribution Algorithm (EDA), the randomness and lack of purpose in the crossover and mutation operations of the traditional NSGA-II algorithm are mitigated, thereby enhancing the optimization performance and convergence speed of the algorithm. Finally, through case analysis, the effectiveness and superiority of this intelligent optimization method in designing CCUS injection parameters are validated.

Abstract

CO2 mineralization sequestration in basalt reservoirs is an emerging and promising pathway for safe and effective CO2 capture, utilization and storage (CCUS), contributing to carbon neutrality. However, the mechanism of CO2 mineralization sequestration involves complex geochemical reactions, which are significantly affected by some factors. Mineral composition, temperature, pH, porosity, permeability and CO2 injection rate are important factors that influence CO2 mineralization in basalt, which require in-depth research and analyses. In this study, a radial model has been constructed using the multi-phase simulator GEM-CMG. This work focuses on the mechanisms of CO2 mineralization and how these mechanisms affect the efficiency of CO2 mineralization sequestration in basalt reservoirs. Sensitivity analyses are performed on the effects of injection mode (supercritical CO2 injection and co-injection of CO2 and water), injection rate and reservoir temperature on CO2 transport and mineralization in basalt reservoirs. The results suggest that more than 60% of the injected CO2 in basalt rocks mineralized within 450 days, and the majority of CO2 was sequestered as magnesite and siderite. Compared to the supercritical CO2 injection, co-injection of CO2 and water can enhance dissolution trapping and thus accelerate the mineral trapping process. In addition, the injection rate has a major influence on the extent of CO2-water-basalt reaction, and the CO2 mineralization efficiency increases with the decrease of the injection rate. Within reasonable limits, higher reservoir temperature is more favorable to efficient CO2 mineralization. This study is of great significance for the understanding of CO2 mineralization mechanism in basalt reservoirs and provides valuable insights for optimizing CO2 mineralization processes.

Abstract

In the face of escalating global climate change, Carbon Capture, Utilization, and Storage (CCUS) technologies have become indispensable for climate change mitigation. The application of carbon dioxide in geological fields, such as Enhanced Oil Recovery (CO2 – EOR) and geological sequestration, presents both promising prospects and significant challenges. There are potential risks of leakage during geological sequestration, which can threaten groundwater and soil environments. Moreover, the long – term impact of carbon dioxide injection on geological structures and their stability remains uncertain. Comprehensive well logging technology has emerged as a powerful tool to address these issues. By continuously monitoring key parameters like formation pressure, temperature, and gas composition in real – time and integrating modern data analysis methods, it can precisely evaluate the effects of carbon dioxide injection, predict and monitor its migration and distribution, and ultimately reduce leakage risks and ensure the safety and long – term stability of geological applications.

Abstract

CO2 flooding presents a promising methodology for enhancing shale gas recovery. To research its feasibility and evaluate the ability of CO2 storage in the shale formations, we established a numerical simulation model of CO2 flooding in shale gas reservoirs based on the embedded discrete fracture model (EDFM). The study analyzed the effects of reservoir properties, well spacing, injection pressure, and injection rate on the CO2 flooding effectiveness in shale gas reservoirs. The CO2 flooding model established in this study employs geological parameters derived from actual shale gas reservoir data, ensuring high levels of authenticity. The research results can provide a reference for oilfields to implement CO2 flooding for enhanced shale gas recovery.

Abstract

This study employs molecular dynamics simulations to investigate how nanostructures influence the wetting behavior of CO2 droplets by varying the solid–liquid interaction coefficient (α), surface feature size, and surface configuration. The results reveal that increasing α drives the transition of droplets from the Cassie state to the Wenzel state. Under identical α, the contact angle on square pillar surfaces is larger than on smooth surfaces. Notably, at α = 0.14, introducing a pillar structure can switch the surface from CO2-philic to CO2-phobic. Further modifications in pillar height and solid fraction induce a Wenzel-to-Cassie transition, significantly increasing the contact angle and reducing CO2–surface interaction energy. Surfaces featuring square pillars, cylinders, or grooves exhibit similar effects in tuning droplet wetting. These insights provide valuable guidelines for optimizing materials and surface designs to enhance CO2 condensation and liquefaction efficiency.

Abstract

In response to global climate change, carbon capture and storage (CCS) has become a key strategy, opening a new chapter in the use of deep underground space. Deep saline aquifers, with their extensive distribution and substantial storage potential, are ideal for CO2 storage. However, the risks of geological storage, including CO2 leakage and potential environmental impacts, cannot be ignored. This study aims to investigate the migration behavior, distribution patterns, and phase changes of CO2 in saline aquifers and their cap rocks through reservoir numerical simulation. A two-dimensional reservoir model was constructed, incorporating a highly permeable pathway to simulate a fault as a leakage channel, in order to study the phase change and longitudinal migration characteristics of CO2 during the leakage process. The simulation results indicate that during the upward leakage process along the fault, CO2, under the influence of buoyancy, tends to enter the upper strata. As it migrates upward, some of the CO2 is affected by rock adsorption and becomes trapped at the interface between the fault and the overlying dense rock of the saline aquifer, distributing stably. It is noteworthy that during the leakage process, CO2 primarily migrates in a supercritical state; however, when it reaches a critical depth, it transitions to a liquid phase. This phase change from supercritical state to liquid state can impact the storage capacity and pressure, thereby affecting the stability of the formations.

Abstract

The caprock selection is challenging due to the potential impact of CO2-caprock reactions on the geological trap stability. In this study, various caprock environments (dolostones, sandstones, shales) with different CO2 storage durations are investigated. Laboratory experiments are conducted to evaluate the deterioration degree of mechanical properties of the damaged caprocks, including tensile and compressive strength, Young’s modulus, and Poisson’s ratio. These analyses enable to assess the caprock stability and further provide the theoretical guidance for CO2 secure storage.

Abstract

During the process of carbon dioxide sequestration in saline aquifers, the presence of impurities in the gas source significantly impacts the temperature and pressure distribution as well as the phase state of the fluid within the wellbore, thereby influencing the injection conditions and geological storage properties. This study established a coupled temperature-pressure model to explore the phase change mechanism of non-pure carbon dioxide flowing through a wellbore. Based on field data, a numerical simulation study validated the effectiveness of the model in predicting temperature and pressure distributions of non-pure carbon dioxide along the wellbore, as well as determining its phase transition position, which could provide a crucial theoretical and decision-making support for wellhead injection technology in the sequestration of non-pure carbon dioxide in saline aquifers.