CO2-enhanced gas recovery (CO2-EGR) offers a dual benefit of boosting natural gas production while enabling carbon sequestration. However, the pore-scale displacement dynamics of CO2-CH4 interactions remain poorly understood due to limitations in conventional observation methods. This study develops an integrated low-field nuclear magnetic resonance (NMR) workflow that combines T2 spectra, stratified T2 spectra, 1D profiling, and NMR imaging to quantitatively monitor and visualize, in real time, the CO2-driven displacement of CH4 in sandstone cores. This integrated method enabled multi-scale visualization of the CO2-EGR process. T2 spectra analysis revealed that CH4 was primarily stored in mesopores, with signal amplitude and peak area reflecting CH4 content and recovery. Stratified T2 spectra offered spatially resolved insights, confirming piston-like migration fronts across core layers. 1D profiling captured axial CH4 distribution and displacement front progression, identifying CO2 breakthrough timing. NMR imaging provided intuitive visualization of displacement morphology, revealing piston-like fronts and CH4 redistribution. This integrated low-field NMR approach proves to be a powerful, non-destructive tool for real-time, multi-scale characterization of gas–gas displacement processes. Results show that CH4 recovery is significantly affected by both permeability and injection rate: high-permeability cores with higher injection rates achieved greater recovery, while low-permeability cores showed limited performance. These findings validate NMR as an effective, non-destructive tool for real-time monitoring and contribute to a better understanding of CO2-EGR mechanisms in heterogeneous reservoirs.

The Sulige Gas Field, currently in the late-stage depletion phase, exhibits substantial potential for CO2 storage. An integrated evaluation methodology was developed, incorporating CO2 caprock pressure breakthrough tests, CO2-water-rock interaction experiments, and CO2 storage simulation experiments to assess the suitability of depleted tight sandstone reservoirs for CO2 sequestration. Key findings include: (1) The minimum caprock breakthrough pressure was determined to be 30 MPa, confirming sufficient sealing capacity; however, horizontal breakthrough risks were found to exceed vertical ones. (2) Dissolution of minerals (calcite, chlorite, and illite) was observed, whereas the caprock pressure-bearing limit remained unchanged at 30 MPa; minor increases in reservoir porosity and permeability were also detected. (3) A negative correlation between water saturation and storage efficiency was quantified, indicating that intermittent injection could mitigate pressure buildup and enhance storage capacity. A novel methodology for CO2 storage capacity estimation has been developed in this study. Application of this approach to the He 8 Member and Majiagou Formation reservoirs in the Sudong Block yields a total estimated CO2 storage potential of approximately 123.9 million tones. This study confirms that sandstone caprocks can effectively confine CO2, highlighting the high suitability of depleted tight gas reservoirs for large-scale CO2 sequestration.

The presence of underlying gas in hydrate reservoirs provides significant commercial potential due to the feasibility of dual-gas coproduction from both hydrate and free-gas zones, leading to enhanced overall gas yields. This study experimentally investigates gas production characteristics in multilayer hydrate reservoirs containing shallow gas, hydrate, and deep conventional gas layers under different extraction sequences. A systematic analysis evaluates how different gas extraction sequences affect pore pressure, temperature, and production characteristics during the process. Results demonstrate that initiating extraction from the deep conventional gas layer yields a higher initial gas production rate. In this scenario, early gas production primarily originates from deep conventional gas, with its contribution gradually declining as hydrate decomposition and shallow gas contributions increase. Conversely, initiating extraction from the shallow gas layer leads to a lower initial production rate but accelerates temperature recovery. Here, early production is dominated by shallow gas beneath the hydrate layer, followed by increasing contributions from deep conventional gas and hydrate decomposition. Furthermore, initiating production from the deep gas layer requires 3.42 times longer to achieve zero pressure differential compared to the shallow-first approach. Therefore, prioritizing shallow gas extraction supports rapid temperature recovery to mitigate hydrate reformation risks, while prioritizing deep gas extraction maximizes short-term gas output. For practical hydrate reservoir exploitation, the choice of the initial extraction layer should be tailored to specific conditions.

Direct injection of liquid CO2 into the ocean for hydrate-mediated sequestration offers advantages in feasibility and capacity, yet faces challenges in rapid hydrate formation and long-term stability in positive buoyancy zones where CO2 density is lower than seawater. Herein, a pilot-scale (ca. 4.5 m) fully visualized vertical riser reactor was used to conduct a series of experiments on dynamic injection of liquid CO2 into simulated seawater (3.5 wt% NaCl solution) at 4.5 MPa and 3 degrees C, investigated the effects of different initial injection velocities on hydrate formation within two flow regimes: varicose breakup and full atomization. Meanwhile, the efficacy of a simple physical trapping device in stabilizing floating multiphase CO2 (droplets and hydrate composite particles) was demonstrated. Results revealed that both regimes enable rapid accumulation of composite particle clusters at the device interface via two distinct solidification mechanisms. High-We atomization reduced droplet sizes to approximately 1/6 of those in low-velocity breakup, facilitating immediate hydrate-cluster formation. Notably, transient contact between ascending CO2 droplets and pioneer hydrate films triggered rapid lateral hydrate shell growth across interfaces. Statistical analysis demonstrated that droplets with a median diameter of 6.3 f 0.3 mm achieved full encapsulation only within 2.7 f 0.4 s, with propagation initiating at contact point and extending to antipodal position. Finally, a two-step injection strategy derived from optimized flow velocities is proposed to enhance CO2 hydrate sequestration efficiency. These findings are expected to progressively establish a novel methodology for marine carbon storage, further contributing to the advancement of global carbon neutrality goals.

Injecting impure CO2 for enhanced gas recovery (CO2-EGR) offers a dual benefit by improving natural gas extraction while enabling CO2 sequestration. However, the interactions between CO2, N2, and CH4 under reservoir conditions require further investigation. This study employs Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) simulations to quantify the adsorption and diffusion behaviors of CO2, N2, and CH4 in quartz nanopores over a pressure range of 1–24 MPa under varying water saturations and gas compositions. The results indicate that: (1) CO2 exhibits the broadest energy distribution and the strongest adsorption stability, occupying about 20 %–30 % more adsorption sites than CH4 or N2 and showing the least sensitivity to water saturation, with only a 30 % reduction at 50 % saturation, compared to 60 % for CH4, giving CO2 a clear competitive advantage. (2) The adsorption and desorption behaviors are strongly pressure dependent, as increasing pressure reduces the adsorption layer area and shifts gas distribution from adsorption dominated to free phase. Competitive adsorption analysis reveals that while CO2 dominates displacement at low pressures, mixtures that contain N2 achieve higher CH4 desorption efficiency above 13 MPa by mitigating diffusion resistance. (3) A higher N2 fraction improves CH4 diffusion coefficients, thereby facilitating gas mobility and ensuring superior recovery performance under high-pressure conditions. This study advances the fundamental knowledge of microscale gas behavior in tight sandstones and supports the feasibility of impure CO2 injection as a practical strategy for sustainable gas production.

Due to its widespread geological distribution and substantial storage capacity, CO2 storage in saline aquifers is internationally recognized as one of the most effective methods for mitigating the greenhouse effect. The characteristics of the two-phase flow in porous media significantly affect the capacity and safety of CO2 storage. In this study, two structures at different locations of the Berea core were obtained and subsequently etched into two different micromodels to investigate the two-phase flow characteristics between CO2 and water. Using a microscopic visualization method, many experimental results have been obtained under different displacement patterns, including qualitative results of the displacement process, interface changes, and phase distributions and quantitative results of differential pressure, CO2 relative permeability, fractal dimension, and CO2 saturation. The results indicated that the maximum CO2 saturation, relative permeability, and fractal dimension were achieved when the displacement pattern was viscous fingering with CO2 predominantly existing in the micromodel as the main displacing channel. On the contrary, when the displacement pattern was capillary fingering, CO2 clusters showed the characteristics of large numbers and small areas, which led to the minimum CO2 saturation, relative permeability, and fractal dimension. Due to the simultaneous dominance of viscous and capillary forces, the flow characteristics under crossover fell between viscous fingering and capillary fingering, rendering them more complex. The phase states of CO2 and water exerted a profound influence on the differential pressure and displacement processes, primarily driven by the viscosity ratio at varying temperatures and pressures. The influence of the micromodel structure on the displacement process was mainly reflected in the local two-phase flow dynamics, resulting in numerical variations without significantly altering the general trend of change.

Geological carbon sequestration (GCS) mitigates climate change by storing anthropogenic carbon dioxide (CO2) in geological formations. CO2 undergoes complex physical and chemical transformations in deep geological formations, governed by various interacting trapping mechanisms. Because the trapping mechanisms operate over a wide range of different timescales, their long-term interplay remains unclear. We develop an integrated numerical modeling framework to analyze and track the plume footprint and phase transition processes that occur throughout the entire cycle of the injected CO2 in saline aquifers. The key novelty of the modeling framework lies in its capability to describe multiple hydrodynamic processes and their interactions, including injection, dissolution-driven convection, reactive transport, and gravity-induced Ostwald ripening. The results suggest that dissolution reduces the lateral migration of free-state CO2, while geochemical reactions generate preferential pathways for CO2-rich flow. For the scenarios we analyze, after 500 years of mass transfer, dissolved CO2 accounts for 42.80 % of total trapped CO2 mass, while reactive CO2 contributes less than 1 %. The results also illustrate that low vertical permeability is unfavorable for the long-term transition of CO2 from physical trapping to dissolution trapping. When the permeability anisotropy index γ increases from 0.5 to 10, the total dissolution storage amount within the domain is reduced to one-third over the 500-year simulation period. This integrated modeling framework provides critical insights into the long-term evolution of CO2 plume migration and phase transition behavior, thereby offering a practical tool to quantitatively assess the long-term fate of the injected CO2 in saline aquifers.

Hydrate-based CO2 sequestration (HBCS) is a promising offshore CO2 geological sequestration technology due to its large storage capacity and long-term stability. However, its large-scale application is hindered by the sluggish CO2 hydrate formation kinetics. Conventional immiscible liquid CO2-H2O contact pattern forms CO2 hydrate film that hinders interfacial CO2 mass transfer for hydrate enclathration. Herein, we report an engineered CO2-in-water (C/W) emulsion system to fundamentally restructure the CO2-H2O contact pattern as dispersed CO2 microdroplets. A stable C/W emulsion was successfully synthesized with a uniform droplet diameter of 14.6 mu m under 12.0 MPa in simulated seawater (3.50 wt% NaCl) by introducing an environmentally benign surfactant alkyl polyglucoside (APG). Furthermore, we examine APG concentration on C/W emulsion stability and CO2 hydrate kinetics by means of kinetic experiments, high-pressure microfluidics, and in-situ Raman spectroscopy. Stable C/W emulsion can be synthesized for CAPG above CMC, achieving optimal stability at 0.30 wt% with a maximum demulsification time of 6.8 h. Compared with non-emulsion systems, CO2 hydrate kinetics achieved in all stable C/W emulsion systems are significantly higher. Highest CO2 final uptake at 188.5 v/v with ultra-rapid CO2 uptake rate of 2.93 v/v & sdot;min-1 was achieved for CAPG = 0.10 wt% in simulated seawater compared with all other kinetic promoter systems. Based on optical microscopy and in-situ Raman observations, closely contacted CO2 microdroplets facilitate spontaneous hydrate nucleation and sustain rapid hydrate growth kinetics by acting as microreactors. This study provides a paradigm shift for enhancing CO2 hydrate kinetics via engineered emulsions, which are meaningful to a series of CO2 hydrate-based applications, e.g., CO2-containing gas separation and desalination.

Time-lapse seismic data provide a powerful tool for monitoring CO2 migration within saline aquifers, such as the Sleipner carbon capture and storage (CCS) Project in the Norwegian North Sea. However, baseline (pre-injection) 1994 seismic data may be affected by random noise, obscuring the identification of key geological elements such as faults, chimneys, and pipes. In this study, we processed the post-stack seismic data using structure-adaptive median filtering to increase the accuracy of interpretation and reveal the influence of sedimentary features and paleo-fluid conduits on CO2 migration within the Utsira Sand. The main objective of this work is to highlight the influence of fluid-escape features on CO2 migration and provide insights for the selection of CO2 storage sites around the world. By integrating variance, root-mean-square (RMS) amplitude, and minimum/maximum amplitude attributes, we identified 100 paleo-pockmarks, 10 pipe conduits, 24 sandstone intrusions, mounds, and polygonal faults from 3D seismic data. A linear regression model was established to analyze the correlations among sandstone intrusions, polygonal faults, and mounds. This model indicated that the sandstone intrusions modified the topography of the saline aquifer's top and base, directing CO2 to preferentially migrate laterally along basal troughs and accumulate beneath the top dome. Paleo-fluid conduits above the storage formation (Utsira Sand) impede lateral CO2 migration by altering the petrophysical properties of the sandstones. These conduits exhibit low-amplitude anomalies internally, while the surrounding strata show high-amplitude anomalies in the seismic data, indicating that CO2 diffuses from the conduits to the surrounding strata and accumulates there. Additionally, CO2 injection reactivates pre-existing fractures associated with paleo-fluid conduits within the saline aquifer, transforming them into chimney-like conduits that facilitate rapid vertical CO2 migration.

The construction of a complementary multi-energy IES has emerged as a key pathway for aligning energy consumption with green and sustainable development. A multi-objective cooperative optimal scheduling model of IES containing hydrogen was proposed on the multi-energy coupling characteristics of IES and the high proportion of access to renewable energy. Leveraging the low-carbon and clean attributes of hydrogen energy, a multi-utilization of hydrogen energy model was developed. It encompasses electrolytic hydrogen production, hydrogen methanation, hydrogen-to-power, carbon capture, hydrogen storage, and hydrogen-doped combined heat and power, enabling full utilization of surplus wind power. Furthermore, a stepped carbon trading mechanism was introduced to further regulate the carbon emission of the system. Considering both economic and low-carbon objectives, a multi-objective optimal scheduling model was formulated to minimize total operational costs and carbon emissions. A combination of ε-constrant method and TOPSIS method was employed for multi-objective solving and decision-making. This study investigated the impacts of multi-utilization of hydrogen energy, various gas-hydrogen blending ratios, and multi-objective scheduling strategies on system performance, thereby validating the effectiveness of the proposed model. The results show that the optimal scheduling enhances the economic and low-carbon performance of IES, facilitating its quantity-quality coordinated operation.

Hydrate-based carbon dioxide (CO₂) sequestration (HBCS) within marine sediments has emerged as a highly promising strategy for long-term carbon storage and climate mitigation. Nevertheless, the efficiency of this process is hindered by the inhibition of clay hydration on CO₂ hydrate formation in marine sediments. This study develops a hydrophobic modification strategy to facilitate hydrate formation by regulating the interfacial water structure at the mineral-water interface. The in-situ formation of CO₂ hydrate and the evolution of water structure were investigated using low-field nuclear magnetic resonance (LF-NMR) techniques and molecular dynamics (MD) simulations. Experimental results demonstrate that the hydrophobic modification of MMT significantly enhances hydrate growth kinetics, achieving a water-to-hydrate conversion rate of ∼41% within 30 min, which is markedly higher than that of raw MMT (∼18%). Transverse relaxation time (T₂) analysis reveals that the hydrophobic modification effectively eliminates the constraints on water molecules imposed by MMT hydration, increases the proportion of free water while reducing the bound water that is reluctant to participate in hydrate conversion. MD simulations further elucidate that the hydrophobic modification creates a “repulsive interfacial environment” through ionic substitution and the hydrophobic effect, which alleviates the confinement of water molecules on the MMT surface and favors hydrate formation. This work highlights that the regulation of interfacial water structure via hydrophobic modification is a critical mechanism for optimizing CO₂ storage in fine-grained marine sediments.

Carbon capture, utilization and storage (CCUS) is a key technology for achieving carbon neutrality, providing the dual benefits of enhanced energy production and reduced CO2 emissions through CO2-enhanced oil and gas recovery (EOR/EGR) and geological storage. However, the large-scale application of CCUS technology faces technical challenges such as engineering design and risk assessment. Traditional approaches, which rely on empirical formulas, experimental verification, and physical models, suffer from low computational efficiency, limited model accuracy, and difficulties in handling multi-dimensional coupling when addressing complex systems. Machine learning (ML), with its powerful data-driven analytical capabilities and adaptive optimization features, can establish high-precision prediction models, optimize operating parameters, predict reservoir fluid behavior, and assess leakage risks. This enables real-time monitoring and intelligent decision-making for complex systems, enhancing the safety and economic efficiency of CCUS technology. This study systematically reviews the applications of ML in CO2-enhanced oil and gas recovery and geological storage. In terms of CO2-enhanced oil and gas recovery, the applications cover percolation mechanism modeling, well pattern design optimization, production prediction and evaluation, multi-objective optimization, minimum miscibility pressure prediction, gas adsorption curve prediction, and CO2-CH4 diffusion assessment. For CO2 geological storage, the applications include reservoir selection, research on CO2 dissolution and diffusion mechanisms, geological storage performance prediction, and risk assessment. ML demonstrates significant advantages in improving prediction accuracy, optimizing operating parameters, and enhancing computational efficiency. It has made important progress in key fields such as reservoir selection, gas adsorption prediction, and storage performance prediction. However, challenges remain in terms of adaptability to complex geological scenarios, model universality, dynamic data processing capabilities, and physical interpretability.

Hydrate-based CO2 sequestration is a novel effective method for sequestrating large amounts of CO2 in subsea sediments. CO2 hydrate stability zone (CHSZ) primarily extends similar to 130 m below the seafloor in South China Sea (SCS) Shenhu area. The location and the amount of liquid CO2 injected are critically important as they determine the fate of CO2 in the long term. In this study, we develop a numerical model to analyze the long-term CO2 sequestration behavior in response to various CO2 injection modes. We systematically design simulation cases to investigate the effects of CO2 injection position in relation to CHSZ, amount of CO2 injection, and the interval of CO2 injection on both short-term and long-term CO2 sequestration performance. The spatiotemporal evolution of CO2 hydrate, liquid CO2, and dissolved CO2 is examined. CO2 injection within the CHSZ yields a relatively thicker CO2 hydrate cap with hydrate saturation gradually decreasing downward, covering liquid CO2 underneath for continuous CO2 hydrate formation. However, CO2 injection across and below CHSZ both results in a much thinner CO2 hydrate cap above the base of CHSZ with inferior CO2 conversion to hydrate, yet liquid CO2 underneath remains stable over 100 years without significant upward migration. Increasing CO2 injection amount practically yields an extended area of CO2 hydrate cap; however, CO2 conversion to hydrate is reduced. Reducing CO2 injection interval further increases near-well overpressure and results in enhanced upward migration of CO2 with risk of potential leakage. Based on the long-term CO2 sequestration behavior, we further propose a method for estimating CO2 storage capacity accounting for stable storage as both liquid CO2 and CO2 hydrate. The findings provide practical guidance for designing an optimal CO2 injection strategy for future offshore CO2 sequestration projects in South China Sea.

Gas hydrate plugging is a common yet hazardous problem during oil and gas reservoir exploitation, compelling the petroleum industry to invest substantial resources annually in mitigation strategies. Two novel hydrate kinetic inhibitors (HKIs), a PVP derivative (PVP-DP) and a PVCap derivative (PVCap-DP), were synthesized and systematically evaluated. Structural characterization by FT-IR, NMR, and TG analyses confirmed increased molecular weights and the introduction of additional polar functional groups relative to the present polymers. In pure water at a subcooling temperature of 6.2 K and a concentration (Cp) of 1 wt%, the methane hydrate induction times (Ih) for PVP-DP and PVCap-DP were 358 min and 395 min, respectively. These values significantly exceed those observed in distilled water (23 min) and in systems containing commercial HKIs, such as PVP (138 min) and VC-713 (272 min). Increasing Cp to 3 wt% further prolonged Ih to 911 min and 964 min, respectively. Even at a higher subcooling of 8.4 K, Ih remained considerable at 126 min and 158 min, demonstrating sustained inhibition under more severe thermodynamic driving forces. Synergistic effects were observed when HKIs (3 wt%) were combined with glycol (1 wt%), resulting in Ih values of 230 min and 268 min. Increasing the glycol concentration to 3 wt% maintained a strong inhibition performance, with Ih values of 211 min and 238 min even at a subcooling of 9 K. In addition, both derivatives exhibited effective inhibition in water/diesel emulsion systems. At 6.2 K subcooling, the PVP-DP (3 wt%)–water/diesel emulsion system achieved an Ih of 404 min, which was markedly longer than that of the uninhibited water/diesel emulsion (51 min), although the emulsion phase moderately reduced the inhibitor efficiency. Overall, PVP-DP and PVCap-DP demonstrate strong kinetic inhibition performance against the formation of natural gas hydrate in both aqueous and emulsion systems, indicating promising application potential in complex production environments.

The accelerating accumulation of anthropogenic CO2 emissions is a major driver of global climate change, emphasizing the urgent need for effective mitigation strategies. CO2-enhanced gas recovery (CO2-EGR) offers dual benefits of improving hydrocarbon recovery while enabling long-term geological storage. However, uncertainties in pore-scale transport mechanisms and rock-fluid interactions hinder reliable implementation. In this study, in-situ CT imaging combined with digital rock reconstruction was employed to investigate CO2-CH4 displacement in carbonate rocks. CT observations showed that prolonged exposure to CO2-saturated brine induced dissolution-dominated reactions with localized precipitation, which increased porosity but also elevated tortuosity and heterogeneity, as reflected in broadened pore size distributions and higher fractal dimensions. Numerical simulations based on a multicomponent convection-diffusion model revealed that mass transfer is governed by a diffusion-dominated mixing front and a convection-dominated trailing region. The mixing front, accounting for similar to 5.5 %-22.8 % of the total mixing zone, provides a clear boundary between diffusion- and convection-driven regimes, with pore connectivity exerting strong control on their persistence. Parametric analyses demonstrated that injection velocity is the primary factor reducing breakthrough and completion times, while pore pressure has a secondary influence via its impact on fluid properties. Temperature and injection composition exert relatively smaller effects at the pore scale, though their significance may increase under reservoir conditions. Rock-fluid reactions further prolonged displacement and enhanced the relative contribution of diffusion. These integrated insights advance the mechanistic understanding of coupled transport processes and offer practical guidance for predictive modeling and optimization of CO2-EGR strategies.

As a key parameter determining fluid flow dynamics, it is significant to determine the dynamic permeability evolution during the hydrate phase transition in consideration of media deformation for the safe and efficient development of hydrate-bearing sediments. In this work, a novel methodology of constructing unstructured hydrate-bearing networks with complex morphologies and anisotropy, respectively, in grain-coating and pore-filling hydrate pore habits coupling media deformation was proposed for the first time. After the validation, dynamic permeability evolution regularity considering media deformation was predicted and analyzed. Furthermore, the impact of parameters related to media deformation on the effective pore structure and dynamic permeability evolution was studied in detail. Results indicate that the effective permeability turns smaller, while the decline rate decreases with increasing hydrate saturation due to the difference in the number and compression degree of hydrate-occupied and unoccupied pore elements induced by media deformation. Moreover, the media deformation effect on the effective pore structure intensifies with an increase in the effective stress, a decrease in the elastic modulus, and a reduction in Poisson's ratio, resulting in a larger decrease in the effective pore-throat radii and reduction in dynamic permeability at the same hydrate saturation. In addition, the number of hydrate-occupied pore bodies and throats grows smaller at the same increment in hydrate saturation as media deformation becomes more pronounced, leading to a slower decline rate and a smaller difference in dynamic permeability with different media deformation parameters.

Ninety-degree branch pipes are widely used in oil and gas transportation networks. This study systematically investigates gas-liquid two-phase flow in 90 degrees confluence sections using integrated experimental and numerical approaches. Three branch configurations (horizontal and vertical), two diameter ratios (0.4 and 0.25), inlet velocities (0.1, 0.2, and 0.3 m/s), and gas volume fractions (5%, 10%, and 20%) are examined. Computational fluid dynamics simulations employ the volume of fluid model coupled with the shear stress transport k-omega turbulence model, while experiments use pressure transducers and signal processing techniques. The results show that branch orientation does not significantly alter laminar formation but affects vortex diffusion pre- and post-confluence. Reducing the diameter ratio from 0.4 to 0.25 quantitatively enhances local turbulence intensity: fluid kinetic energy increases by 45% at the branch inlet and 37% at the confluence, while the pressure drop rises by up to 35%. When the inlet velocity increases from 0.1 to 0.3 m/s, the confluence pressure drop increases by approximately 70%. A gas volume fraction exceeding 10% intensifies recirculation in the vertical branch, whereas an inlet velocity above 0.3 m/s suppresses it. Dual-branch pipes exhibit a turbulence intensity 44% higher than single-branch pipes under identical conditions. Higher gas volume fractions (e.g., 20% vs 10%) enhance turbulence intensity and flow stability but increase pressure drop fluctuations, and these quantitative findings elucidate the coupled effects of diameter ratio and gas content on vortex diffusion, turbulence enhancement, and pressure pulsation in 90 degrees branch pipes, advancing the understanding of flow evolution in small-diameter-ratio branch pipes.

Hydrate-based CO2 storage represents a compelling strategy for CO2 oceanic storage. The long-term stability of CO2 hydrates is the pivotal indicator for assessing the technical viability of this strategy. Investigation on CO2 hydrate stability can not only quantify the risk of CO2 leakage to the environment, but also provide the mechanistic basis for optimizing long-term, secure storage. The hydrate dissolution rate serves as the quantitative proxy for hydrate stability. Accurate quantification of CO2 hydrates dissolution rates in marine settings is therefore imperative. This study presents a comprehensive, 200-hour experimental program to quantify the dissolution rate of CO2 hydrate under submarine sediments environment. The porosity and true density of the reconstructed sediment used were 45% and 2.8 g/cm3, respectively. Factors such as temperature, pressure, and sediment cap thickness were investigated to determine the dissolution rate of CO2 hydrates under different conditions. The dissolution rate of CO2 hydrates increases modestly with rising temperature and pressure, yet declines precipitously as sediment cap thickens. Across the investigated parameter space, the dissolution rate spans 4.87-134.73 cm/year. In diffusion-controlled hydrate dissolution, the sediment cap dramatically suppresses the CO2 molecular diffusion flux by simultaneously lowering porosity and increasing tortuosity. Over long-term evolution, once the local temperature and pressure conditions are established, the sediment cap thickness emerges as the predominant factor controlling the hydrate dissolution rate. These findings provide a mechanistic basis for assessing the long-term stability of CO2 hydrates during storage and offer critical guidance for the design of enduring CO2 hydrate storage strategies.