CO2 Hydrate Research Articles

Collective molecular-scale carbonation path in aqueous solutions with sufficient structural sampling: From CO2 to CaCO3.

The carbonation reaction is essential in the global carbon cycle and in the carbon dioxide (CO2) capture. In oceans (pH 8.1) or in synthetic materials such as cement or geopolymers (pH over 12), the basic pH conditions affect the reaction rate of carbonation. However, the precipitation of calcium or magnesium carbonates acidifies the environment and, therefore, limits further CO2 capture. Here, we investigate how pH influences carbonation pathways in neutral and basic solutions at the atomic scale using reactive molecular simulations coupled with enhanced sampling methods from CO2 to calcium carbonate (CaCO3). Two distinct CO2 conversion pathways are identified: (1) CO2 hydration: CO2+H2O⇌H2CO3⇌HCO3-+H+⇌CO32-+2H+ and (2) CO2 hydroxylation: CO2+OH-⇌HCO3-⇌CO32-+H+. The CO2 hydration pathway occurs in both neutral and basic aqueous solutions, but reactions differ significantly between the two pH conditions. The formation of the CO32- is characterized by a markedly high free energy barrier in the neutral solution. The CO2 hydroxylation pathway is only found in basic solutions. Notably, the CO2 molecule exhibits a pronounced energetic preference for reacting with hydroxide ions (OH-) rather than with water molecules, resulting in significantly reduced free energy barriers along the CO2 hydroxylation pathway. The reaction rate estimation suggests that the CO2 hydroxylation path is the most favorable carbonation pathway in the basic solution. Once the CO32- anion is formed in the presence of alkali-earth (e.g., Ca2+ and Mg2+) cations, carbonate formation can proceed.

Thermal analysis and kinetic investigation of using a hybrid adsorption-hydration method to promote CO2 capture

In this work, a hybrid adsorption-hydration method was utilized to promote CO2 capture. The CO2 capture performance in the fixed bed of coal particles was assessed at various water saturations (0 %, 20 %, 40 %, 70 %, and 100 %), 277.15 K, and 3.2 MPa. It was found that gas consumption at 100 % water saturation increased by 45 % compared to that at 0 % water saturation (dry coal particles). Moreover, as the water saturation increased, CO2 capture became dominated by hydrate formation rather than gas adsorption. The thermal analysis for CO2 capture at 0 % and 100 % water saturation detected the exothermic peaks associated with CO2 adsorption and CO2 hydrate formation, as well as the endothermic peaks corresponding to CO2 desorption and CO2 hydrate dissociation. This confirms that CO2 capture in the fixed bed of water-saturated coal particles consists of CO2 adsorption followed by hydrate formation. The morphologies of CO2 hydrate formation in the fixed bed of 100 % water-saturated coal particles were observed, and the mechanism of CO2 capture using the hybrid adsorption-hydration method was illustrated based on the thermal analysis and kinetic investigations. It was also found that after the adsorption-hydration process, the average cumulative pore volume of the coal particles decreased by 14.47 % compared to the original coal particles, and the micropores and mesopores were predominantly affected. Therefore, utilizing the hybrid adsorption-hydration process in a fixed bed of coal particles provides a promising method to enhance CO2 capture.

Carbon dioxide hydrate formation in porous media under dynamic conditions

AbstractInjecting carbon dioxide (CO2) into subsea water zones where the in situ temperatures are below the hydrate‐forming temperature of CO2 has been recently proposed to lock CO2 inside the water zones in solid hydrate form. It is a common concern that CO2 may form hydrates during the injection period that will reduce well injectivity. CO2 injection into sandstone cores under simulated subsea temperatures of 2°C and 3°C was investigated in this study. Experimental result shows that, at 2°C temperature, flowing CO2 at Darcy velocity 0.033 cm/s begins to form hydrate in the sandstone core at about 3.06 MPa (450 psi), which is much higher than the minimum required pressure of 1.5 MPa (220 psi) for CO2 to form hydrate in static condition. The pressure ratio is 450/220 = 2.05. At 3°C temperature, flowing CO2 at Darcy velocity 0.045 cm/s begins to form hydrate in sandstone core at about 3.67 MPa (540 psi), which is much higher than the minimum required pressure of 1.87 MPa (275 psi) for CO2 to form hydrate in static conditions. The pressure ratio is 540/275 = 1.96. The reason why the required minimum pressure for CO2 to form hydrates in dynamic conditions is about double the required hydrate‐forming pressure in static conditions is not fully understood. It is speculated that the shear rate effect of flowing fluids should slow down the growth of hydrate crystals or break down hydrate films, resulting in delayed formation of bulk CO2 hydrates. More investigations in this area are needed in the future.

Deciphering the CO2 hydrates formation dynamics in brine-saturated oceanic sediments using experimental and machine learning modelling approach

One of the potential strategies for limiting global warming is capturing excess amounts of industry CO2 emissions and sequestrating it inside the oceanic sediments as CO2 hydrates. The seabed consists of sediments with different porosity and sizes, which can significantly impede the kinetics of CO2 hydrates. To address these challenges, in this novel work the CO2 hydrate kinetics and morphologies have been investigated in brine-rich [3.5 wt% NaCl] coarse sediments [porosity = 0.28, Ø =0.5-1.5 mm], granule sediments [porosity = 0.43, Ø =1.5-3 mm] and dual sediments [coarse + granules] inside a high-pressure reactor [3.5 MPa, 1-2 oC] with artificial seabed. According to the key experimental results, the water-to-hydrate conversion [%] was estimated to be 67.24 (± 3.02) % for coarse sediments, 49.58 (± 4.97) % for dual sediments (coarse + granules), and 27.68 (± 5.21) % for granules. In-situ Raman spectroscopy was used to evaluate the real-time solubility of CO2 [0.023 mol/mol], and image processing thresholding was used to identify CO2 hydrate distribution patterns. A mathematical model was proposed as a major contribution to predict CO2 hydrates kinetics in sediments, using 94,203 data points. The model was trained via a supervised machine-learning [ML] algorithm and can predict CO2 hydrate kinetics with an AARD of 7.54-8.47%.

Dependence of the hydrate-based CO2 storage characteristics on sand particle size and clay content in unconsolidated sediments

Storing carbon dioxide (CO2) in the form of hydrate in marine sediments is considered an effective way of carbon reduction. Understanding the influence of sediment properties on CO2 hydrate formation is important for the site selection of CO2 hydrate storage in marine sediments. In this study, the effects of sand particle size and bentonite content on the kinetics of CO2 hydrate formation are analyzed using low-field nuclear magnetic resonance technology, and the hydrate-based liquid CO2 storage capacity is evaluated. Results show that CO2 hydrate forms preferentially in large pores of sand samples, the water content in small pores begins to decrease before the hydrate saturation reaches 20%, and the unhydrated water mainly concentrates in small pores. With the increase of sand particle size, the CO2 storage rate of the early rapid growth stage increases first and then decreases, the CO2 storage rate of the whole hydrate formation process decreases continuously, but the final CO2 storage density is weakly affected by sand particle size. With the increase of hydrate saturation, the CO2 storage rate undergoes a trend of rapid decrease, stability, rapid decrease, and low-speed decrease in sequence. The larger the sand particle size or the higher the bentonite content, the shorter the stability stage of CO2 storage rate. The effect of bentonite on CO2 storage rate is the promotion at low content, the inhibition at medium content, and the weakening of inhibition at high content. The sediments with more than 25% bentonite are beneficial to the storage of more CO2.

CO2 hydrate formation in superabsorbent hydrogels for carbon capture—A comparison of water-confined framework vs non-water framework

This study investigates the kinetics of CO2 hydrate formation in saturated hydrogel particles—water-confined frameworks—through both experimental and numerical methods, and compares the results with those obtained in silica gels, silicon-based frameworks. Three hydrogel materials with varying swelling ratios were synthesized via radical polymerization. An advanced shrinking core model was developed, incorporating factors of CO2 solubility, gas diffusion, gas–water reaction, capillary effects, and hydrogel functional groups. Results showed rapid CO2 hydrate growth within the first 100 min, with CO2 uptake reaching 78%–82% of the final amount by 600 min. The highest percent water conversion achieved was 96.6%. Simulations indicated a significant decrease in CO2 diffusion coefficient through the hydrate shell over time, especially in hydrogels with higher methacrylic acid content. Capillary effects diminished as the reaction proceeded, with final water consumption via capillaries accounting for 14.4%–26.7% of the total. Hydrogels with higher swelling ratios and higher agglomeration degree formed more porous hydrate shells, enhancing CO2 diffusion but resulting in lower overall CO2 uptake due to their lower water content. Comparisons with hydrophilic porous silica gel revealed that, although hydrogels initially posed greater mass transfer resistance, they ultimately exhibited superior CO2 absorption capacity and rate.

Capacity planning of storage batteries for remote island microgrids with physical energy storage with CO2 phase changes

Energy storage devices based on the CO2 thermal cycle (CTC) lose competitiveness in cold regions because of the decreased energy volume density and charge–discharge efficiency at low ambient temperatures. The CO2 hybrid thermal cycle (CHS) combines the CTC with the CO2 hydrate thermal cycle (CHT) to maintain a high energy volume density and charge–discharge efficiency regardless of the ambient temperature. The CHS-based energy storage system has been shown to have an energy volume density of 80–140 kWh/m3 and charge–discharge efficiency of 60 %–106 %. However, the economic feasibility of this system has not been considered. In this study, a numerical analysis was performed on the practical application and economic feasibility of CHS-based energy storage for the 100 % renewable energy microgrid of a pair of remote islands. In a case analysis of CHS installation in a microgrid for a remote island with 100 % renewable energy, the construction cost of CHS was 2/3 of that of pumped storage; the equipment cost reduction of CHS strongly depends on the type and amount of renewable energy to be interconnected, and therefore, the overall optimization of the power system is necessary.

Hydrate management strategies for CO2 injection into depleted gas reservoirs

Sequestering CO2 in depleted gas reservoirs using carbon capture, utilization, and storage technologies has emerged as a viable strategy for mitigating global carbon emissions. However, CO2 hydrate formation during injection processes is challenging and poses a risk to the operational integrity and efficiency of sequestration projects. This study investigated CO2 hydrate formation dynamics within silica gel environments that closely mimicked the median pore size of natural sandstone reservoirs, particularly targeting depleted gas fields in the East Sea of Korea. Integrating kinetic insights into experimental hydrate formation assessments and molecular dynamics simulations provided a comprehensive understanding of the CO2 hydrate formation mechanisms, as well as the formation dynamics and stability of the CO2 hydrates. For example, the hydrate formation kinetics were significantly reduced in the small pores, suggesting the feasibility of implementing more economical hydrate inhibitor injection strategies during CO2 injection. Moreover, this study evaluated the inhibitory effects of NaCl and methanol on CO2 hydrate stability by accurately measuring the three-phase (H-Lw-V) equilibria and employing silica gels (6 nm pore size). The presence of methanol and amorphous silica significantly impacted hydrate formation, with methanol potentially influencing the local structure around the hydrate phase and silica hindering hydrate growth through dynamic interactions with CO2 molecules. In addition, we elucidated the complex interplay between CO2, water, and methanol (hydrate inhibitor) within the constrained environments of porous media, offering strategic insights for the development of effective CO2 injection and sequestration strategies. Integrating molecular-level observations with real-world geological modeling presents a novel methodology for enhancing the safety, efficiency, and environmental sustainability of carbon capture and storage operations. The findings of this study provide critical insights into hydrate phase behavior, highlighting the importance of precise equilibrium determination under simulated reservoir conditions to effectively anticipate and mitigate hydrate formation challenges.

Numerical modelling of CO2-in-water emulsion injection into a water-saturated core

Depressurization method shows promise for methane hydrate (MH) reservoir production, but the reformation of hydrates due to a lack of geothermal heat presents a significant challenge for commercial production. This study proposes a novel approach for MH gas recovery by injecting a CO2-in-water (C/W) emulsion into an MH reservoir aquifer. The exothermic nature of CO2 hydrate formation and liquid CO2 dissolution in water in this method provides heat to the MH layer, effectively preventing hydrate reformation. Subsequently, 1-D numerical models were developed and implemented using the MATLAB Reservoir Simulation Toolbox (MRST). These models were rigorously validated against experimental data under homogeneous conditions and varying injection schemes. The investigation indicated that the average volume fraction of CO2 hydrate within the hydrate particles was found to be 55% of the volume of liquid CO2 droplets. The alternating C/W emulsion injection increased the driving force for CO2 dissolution in water, thereby promoting subsequent hydrate particle decomposition and CO2 hydrate dissolution in water, which effectively mitigated blockage within the porous medium. In conclusion, water alternating C/W emulsion injection, along with the continuous injection of a low volume fraction of liquid CO2 within the C/W emulsion, exhibits promising potential for sustained injection and provides adequate heat to the MH layer, preventing hydrate reformation. Furthermore, the developed numerical model reasonably predicts the behavior of various injection schemes. This developed model can be used for devising long term sub-seabed carbon capture and storage development plan.

Kinetics of CO2 hydrate formation in clayey sand sediments: Implications for CO2 sequestration

Hydrate-based CO2 sequestration beneath oceanic sediments is an emerging technique that involves the injection of CO2 into the hydrate stability zone (HSZ) beneath the seabed, forming hydrate cap that structurally traps the injected CO2 and reduces the risk of leaking CO2 from the storage sediment. Gas hydrates are adequately stable in sand sediments saturated with fresh water; however, the salinity of oceanic water impairs hydrate formation kinetics, stability, and CO2 storage capacity. In addition to sandstones, marine sediments are composed of many clay minerals that could affect hydrate formation. Therefore, this study experimentally simulates CO2 injection into sand and clayey sand sediments to assess the potential of CO2 hydrate formation. CO2 hydrates are formed inside a high-pressure reactor, which contains unconsolidated sediment bed/pack (silica sand; mixed sand with bentonite clay: 5 wt% and 10 wt%), saturated with de-ionized water or brine (3.3 wt% NaCl). Hydrate formation experiments were performed at 4 MPa pressure and 274.15 K temperature. Results show that CO2 hydrate formed within the sand sediment, with induction times of 6 and 8.5 h, for the de-ionized and brine systems, respectively. CO2 gas mole uptake in the de-ionized system was 71.54 mmol/mol however, in the brine system the gas uptake was 56.95 mmol/mol. Hence this 20.4% reduction in the gas uptake indicated the inhibition effect of salinity. In contrast, in the brine-saturated 5 wt% clay-sand sediment, the induction time was 6.5 h, indicating the promoting effect of the nano-sized clay particles. However, the gas uptake in this brine-saturated clay-sand sediment was reduced by 45.51% compared to the brine-saturated sand sediment. Increasing the clay content to 10 wt% prevented CO2 hydrate formation due to porosity reduction. Moreover, de-ionized water in clayey sand sediments prevented hydrate formation due to clay swelling. Finally, CO2 hydrate formation at the end of each experiment was visually confirmed.

Bicarbonate-mediated proton transfer requires cations

Near-neutral HCO3– aqueous solution plays an essential role in respiratory, mineralization and catalysis, yet the interconversion between hydrated CO2, HCO3– and CO32– and the associated proton transfer under such proton-deficient conditions remain uncovered. Here we reveal that cation enables HCO3– to self-dissociate into OH– and CO2 through a pH-independent process, where CO2 hydration and subsequent proton transfer in acid-base reactions lead to the overall exchange of oxygen isotopes between HCO3– and H2O tracked by oxygen isotope-labeled Raman spectroscopy. Isolating HCO3– from cations with crown ether impedes HCO3– dissociation and the following reactions. Further molecular dynamics simulations demonstrate that the interplay between HCO3– and hydrated cations drives HCO3– dissociation. This study suggests a natural proton channel upon coupling HCO3– with cations.

Enhanced Study of CO2 Hydrate Formation in Marine Oil–Gas Based on Additive Effect

During marine oil–gas extraction, significant amounts of carbon dioxide (CO2) gas are often produced. Effectively separating these associated CO2 gases during extraction has become a critical technical challenge. Therefore, this paper aims to enhance the efficiency of CO2 hydrate-based capture technology and conduct relevant research. The goal is to increase the driving force for hydrate formation by combining the traditional thermodynamic additive TBAB with pressure modulation and to improve the hydrate formation rate through the use of multiple kinetic promoters. This paper presents the initial investigation into the effect of the thermodynamic accelerator tetrabutylammonium bromide (TBAB) on the characteristics of CO2 hydrate formation. The promotion effects of TBAB solutions with varying mass concentrations (3%, 5%, 7.5%, 10%) and reaction pressures (3 MPa, 4 MPa) were subjected to a systematic analysis, and the optimal conditions were identified as 4 MPa and a 5 wt% TBAB concentration. Subsequently, the impact of combining TBAB with kinetic promoters (SDS, nano Al2O3, L-methionine, L-leucine) on CO2 hydrate generation characteristics was further investigated. In this paper, the effect of a single promoter on the generation characteristics of CO2 hydrate was investigated, and the efficient carbon trapping ability of the complex promoter was verified, which provides theoretical support for the application of CO2 trapping technology using the hydrate method.

Evaluation of the synergic effect of amino acids for CO2 hydrate formation and dissociation

Gas hydrate formation is a very challenging problem in the oil and gas industry. The chemical inhibition method is the best practicable hydrate mitigation method by injecting hydrate inhibitors such as Thermodynamic Hydrate Inhibitors (THIs) and Kinetic Hydrate Inhibitors (KHIs) into the pipeline. However, the hydrate inhibitors' biodegradability and limited data on dual functional inhibitor mixtures raise concerns in this study. This study aims to investigate and compare thermodynamic and kinetic inhibition on CO2 hydrate by using biodegradable amino acid inhibitor mixtures of Glycine and Alanine. In this study, the inhibitor mixtures were prepared by mixing Glycine and Alanine in 3 different mixture ratios, followed by the Thermodynamic and Kinetic inhibition tests. Thermodynamic Inhibition Test was conducted by using 10 wt% of inhibitor mixtures in a CO2-water system under pressure of 4.0, 3.5, 3.0 and 2.5 MPa, while Kinetic Inhibition Test was carried out by using 1 wt% of the sample in the CO2-water system at a constant pressure of 4.0 MPa and temperatures at 274.15K. The analysis methods for the Thermodynamic Inhibition Test were Hydrate Liquid-Vapor Equilibrium (HLVE) Curve, Average Depression Temperature and Molar Dissociation Enthalpy, while the Induction Time method, the number of CO2 moles consumed, the formation rate of CO2 gas hydrate and RIP were used in the Kinetic Inhibition Test. In this study, all inhibitor mixtures exhibit dual functional inhibition on the CO2 hydrate. For THI, 50% Gly: 50% Ala shows the best thermodynamic inhibition strength with an average depression temperature of 2.42 K. All the inhibitor mixtures for THI have the dissociation enthalpies within the CO2 hydrate enthalpy range, which show that the inhibition is due to the influence on the water molecules’ interaction only. For KHI, 75% Gly: 25% Ala shows the highest kinetic inhibition strength on CO2 formation with the longest induction time of 115.2 min and the highest RIP of 0.40. In the KHI experiment, there is a drop in the CO2 uptake capacity with the presence of inhibitors used, where the highest difference of CO2 moles consumed is 0.0057 mol. A synergistic effect of inhibitor mixtures was observed in this study on 50% Gly: 50% Ala for THI and 75% Gly: 25% Ala for KHI. However, the “degradation” effect was also exhibited on 75% Gly: 25% Ala and 25% Gly: 75% Ala for THI and 50% Gly: 50% Ala and 25% Gly: 75% Ala for KHI, where the performance of the inhibitor mixtures is poorer than the concentrated amino acids. The “degradation” effect of the inhibitor mixtures at certain ratios was not covered in this study and it requires a further understanding of the chemistry behind the inhibition mechanism.

How shallow CO2 hydrate cap affects depressurization production in deeper natural gas hydrate reservoirs: An example at Site W17, South China Sea

The logging results from the Shenhu Sea show that the P-T conditions of NGH deposits are below the CO2 hydrate phase equilibrium curve. The burial depth difference between the CO2 hydrate stable zone and NGH deposits is usually above 100 m, which differs from the laboratory scale. Thus, whether CO2 hydrate caps can provide pore sealing and reinforcement of natural gas hydrate (NGH) overburden at the engineering scale is unknown. Based on this, we aimed to perfect research on the CO2 hydrate cap, including its formation process, effects on NGH exploitation, geomechanical response, and comprehensive benefit evaluation, by establishing a THMC model based on Site W17. Results indicate that (i) CO2 can form hydrates in the overburden layer with a conversion rate of about 28%, preventing the upward escape of residual liquid CO2 due to density difference. (ii) CO2 injection and CO2 hydrate cap formation can increase the decomposition driving force during depressurization to enhance production, but it fails to inhibit water invasion from the upper part of the NGH deposit due to the excessive depth difference. (iii) The CO2 hydrate cap causes strata uplift, thereby mitigating strata subsidence during depressurization production, especially for the cases of horizontal wells, where the subsidence is reduced by about 103.4%. (iv) Injecting too much CO2 may not benefit gas production, where part of the free gas will convert into NGH due to pressure rise. The optimal injection rate in this study is 40,000 m3/d. (v) Indicators like CO2 hydrate conversion rate, gas-water ratio, and maximum strata displacement show that horizontal well systems with CO2 hydrate caps are more beneficial than vertical well systems, and multi-branched well systems are more beneficial than single-direction well systems. These key findings may differ from the laboratory scale, which can provide a reference for applying CO2 hydrate caps in actual NGH exploitation.

A calorimetric and Raman spectroscopy study on the phase behavior of DIOX + CO2 hydrate

This work presents a calorimetric and Raman spectroscopy investigation on the phase behavior of DIOX (1,3-Dioxolane) + CO2 hydrate. A high-pressure micro-differential scanning calorimeter (HP μ-DSC) was used to determine the phase equilibrium data of DIOX + CO2 hydrate formed at 1 mol% and 5.56 mol% DIOX. A high-pressure in situ Raman spectroscopy apparatus was used to record the transient CO2 Raman spectra. The spectra were employed to study CO2 incorporation into the hydrate cages during the DIOX hydrate formation process. The results indicate that the DIOX + CO2 hydrate formed at 5.56 mol% DIOX is more stable than that formed at 1 mol% DIOX. The amount of DIOX + CO2 hydrate is increased when increasing the pressure from 3.0 MPa to 4.8 MPa, and more CO2 molecules are captured in the hydrate. Through the in situ Raman spectroscopy experiments, it is found that DIOX hydrate formed quickly at the beginning of the experiment and CO2 molecules were trapped in the small cages more slowly than the incorporation of DIOX into the hydrate. The results reported in this work have confirmed the feasibility of using DIOX as a thermodynamic additive to promote the hydrate-based CO2 capture.

Phase Stability of CH4 and CO2 Hydrates under Confinement Predicted by Machine Learning.

Understanding the phase stability of gas hydrates under confinement is fundamental to the geological stability evolutions of gas hydrate systems on Earth. Herein, the phase stability of CH4 and CO2 hydrates under confinement is predicted by machine learning. Three machine learning models, including support vector machine, random forest, and gradient boosting decision tree, are constructed to predict the phase stability of CH4 and CO2 hydrates under confinement. Our machine learning results show that the prediction accuracy of the support vector machine model is highest, yet the prediction accuracy of the random forest model is lowest among those machine learning models in determining the phase stability of confined gas hydrates. Based on their performance in predicting the phase stability of confined gas hydrates, the support vector machine model with a training set fraction of 0.7 is finally chosen to deal with the unknown phase stability of confined gas hydrates. Importantly, the average accuracy of the support vector machine model can reach more than 90% in predicting the unknown phase stability of both CH4 and CO2 hydrates. The trained machine learning models can help us to quickly and accurately determine the phase stability of CH4 and CO2 hydrates under confinement in future applications.

The role of phase saturation in depressurization and CO2 storage in natural gas hydrate reservoirs: Insights from a pilot-scale study

The natural gas recovery and CO2 storage in natural gas hydrate (NGH) reservoirs is a promising integrated strategy for implementing clean energy production and CCUS. However, the fundamental characteristics (phase saturation) of NGH reservoirs on the feasibility and efficiency of the above-integrated processes remain unclear. In this study, we synthesized methane hydrate-bearing sediments (MHBS) with varying hydrate saturation (SH = 18–66 %) and aqueous saturation (SA = 7–92 %) at marine NGH conditions (T = 283.8 K, P = 11.0 MPa). The effect of phase saturation on depressurization-induced hydrate dissociation, and subsequent CO2 storage and hydrate restoration by CO2/N2 injection was investigated. The water-saturated MHBS with high SA can promote faster MH dissociation during the depressurization stage and prevent secondary hydrate formation, but a slower MH dissociation during the later stage due to slow heat transfer. A relatively high SH (> 63 %) results in sustained low temperatures due to insufficient heat supply slowing down MH dissociation. The CH4/CO2/N2 mixed hydrates (Mix-H) formation and CO2 storage in depleted MHBS after CO2/N2 injection initially increase and then decrease with post-mining SA (peak at SA = 54.5 %). The rate of Mix-H formation decreases as the post-mining SA increases. Higher pre-mining SH and CO2/N2 injection rate facilitates rapid gas phase mixing within the sediments, thereby improving the kinetics and homogeneity of Mix-H formation and hydrate-based CO2 storage efficiency. MHBS with relatively low SH and SA exhibit enhanced safety for the integrated process, offering reduced depressurization-induced sediment subsidence and increased hydrate restoration ratios (∼85 %) by Mix-H formation.

Mechanistic insights into pore water conversion to gas hydrates in clay minerals

The conversion of pore water to gas hydrates is an important prerequisite for natural gas hydrates (NGHs) accumulation and hydrate-based CO2 sequestration. However, the mechanism of water-to-hydrate conversion in clays, which are prevalent in hydrate reservoirs or marine sediments serving as potential hosts for CO2 hydrates, still remains poorly understood, impeding further advancements in exploiting NGHs and developing CO2 sequestration strategies. In this paper, the characteristics of pore water conversion to hydrates in montmorillonite and kaolin were comprehensively examined through quantitative measurements and NMR analysis, and compared with those in silt and coarse sand. It revealed that the water-to-hydrate conversion was more restricted in clays than in sands. Especially in montmorillonite, since almost all pore water was detected as bound water, the final water conversion was extremely low and sensitive to the subcooling degree. Additionally, as the initial water content increased from 15 wt% to 35 wt%, the final water conversion in kaolin, silt, and coarse sand decreased exponentially due to intensified kinetic limitation, whereas that in montmorillonite initially rose and then fell, attaining the maximum at a threshold of 20 wt%. It is found that the competition between thermodynamic and kinetic limitations controls water-to-hydrate conversion in clays. Specifically, in kaolin, silt and coarse sand, the main controlling factor of water-to-hydrate conversion is the kinetic limitation, as their unconverted equilibrium water is negligible. However, in montmorillonite, the thermodynamic limitation dominates at low water contents, transitioning to kinetic limitation at high water contents. This study provides direct evidence and mechanistic insights into how clays affect water-to-hydrate conversion in porous media, which has significant implications for the geological accumulation of NGHs and the site selection for hydrate-based CO2 sequestration.

Clay mineral mediated dynamics of CO2 hydrate formation and dissociation: Experimental insights for carbon sequestration

Marine sediment-based CO2 sequestration through hydrate formation is a promising approach for long-term CO2 storage. Despite the prevalence of clay minerals in marine sediments, their impact on CO2 hydrate dynamics remains disputed and necessitates validation. This study systematically investigated the effect of clay minerals, specifically Ca-montmorillonite (Ca-mmt) and illite, on CO2 hydrates nucleation, growth, and dissociation in clay suspensions (0–10 wt% concentrations). Clay minerals significantly promoted CO2 hydrate nucleation by providng additional nucleation sites and influencing water distribution through the surface electric field. Ca-mmt exhibited a more pronounced nucleation effect due to stronger hydration ability of Ca2+ increasing nucleation sites and local CO2 concentration. Both clay minerals enhanced CO2 hydrate growth, with concentration-dependent effects that differ between clay types. Ca-mmt exhibited a higher growth rate at lower concentrations (≤1 wt%), but a lower rate at higher concentrations (>1 wt%) due to the stronger swelling and aggregation ability upon water contact. Morphological analysis revealed the clay minerals’ impact on fluid behavior and mass transfer during hydrate growth. During dissociation, clay minerals impeded the process, prolonging overall dynamics. This study highlights the impact of physicochemical disparities between Ca-mmt and illite on CO2 hydrate dynamics, underscoring the importance of these interactions for CO2 sequestration.

Optimizing CO2 Hydrate Sequestration in Subsea Sediments through Cold Seawater Pre-Injection

Carbon sequestration technology offers a solution to mitigate excessive carbon dioxide emissions and sustainable development in the future. This study proposes a method for subsea carbon sequestration through the injection of cold seawater to promote CO2 hydrate formation. Using a self-developed simulator, we modeled and calculated the long-term sequestration process. The study focuses on analyzing the thermal regulation of the seabed following cold seawater injection, the multiphysical field evolution during CO2 injection and long-term sequestration, and the impact of seawater injection volumes on sequestration outcomes. The feasibility and leakage risks of this method were evaluated on a 100,000-year timescale. Results indicate that the injection of cold seawater significantly improves the pressure–temperature conditions of subsea sediments, facilitating early hydrate formation and markedly increasing the initial CO2 hydrate formation rate. Consequently, the distribution pattern of hydrate saturation changes, forming a double-layer hydrate shell. Over the long term, while cold seawater injection does not significantly reduce CO2 leakage, it does increase the safety margin between the hydrate layer and the seabed, enhancing the safety coefficient for long-term CO2 hydrate sequestration. Through detailed analysis of the behavior of CO2 components during sequestration, this study provides new theoretical insights into subsea CO2 hydrate storage.