Hydrate-based CO₂ sequestration is a novel approach that can not only realize permanent CO₂ sequestration but can also form an artificial cap to prevent its upward migration. In this work, a self-developed large-scale 3D apparatus was employed to investigate hydrate formation characteristics in hydrate-based CO₂ sequestration at a constant liquid CO₂ injection rate through a vertical well for the first time. Temperature and pressure evolutions in the sediment were analyzed in detail. Key indicators, including cumulative sequestered CO₂, CO₂ in hydrate and liquid phases, the instantaneous hydrate conversion, and liquid CO₂ retention rates, were calculated. The results show that hydrate continuously forms with increased CO₂ injection and exhibits strong heterogeneity due to the variation in hydrate formation rate and quantity. Severe liquid CO₂ heterogeneous figuring phenomena occur since hydrate deteriorates the effective pore structure and topology, resulting in relatively small cumulative sequestered CO₂ when a large amount of CO₂ is released from the outlet. Meanwhile, the instantaneous hydrate conversion and liquid CO₂ retention rates have large fluctuations owing to water consumption and variation in the effective contact area between liquid CO₂ and water. However, hydrate formation does not cause blockage of wellbore and formation nearby under given experimental conditions, which is beneficial for hydrate formation in deeper sediment. This study provides insights into hydrate formation and liquid CO₂ immigration regularity during hydrate-based CO₂ sequestration and demonstrates its feasibility at a field scale.

The aim of this study was to determine the influence of four inorganic salts, KCl, NaCl, KBr and NaBr, on the thermodynamic conditions of methane hydrate formation. In order to achieve this, the vapor–liquid water-hydrate (VL_WH) equilibrium conditions of methane (CH₄) hydrate were measured in the temperature range of 274.15 K–282.15 K by the isothermal pressure search method. The results demonstrated that, in comparison with deionized water, the four inorganic salts exhibited a significant thermodynamic inhibition on CH₄ hydrate. Furthermore, the inhibitory effect of Na⁺ on methane hydrate is more pronounced than that of K⁺, where there is no discernible difference between Cl⁻ and Br⁻. The dissociation enthalpy ($∆H_{diss}$) of CH₄ hydrate in the four inorganic salt solutions is comparable to that of deionized water, indicating that the inorganic salt does not participate in the formation of hydrate crystals. The Chen–Guo hydrate model and N–NRTL–NRF activity model were employed to forecast the equilibrium conditions of CH₄ hydrate in electrolyte solution. The absolute relative deviation (AARD) between the predicted and experimental values were 1.24%, 1.08%, 1.18% and 1.21%, respectively. The model demonstrated satisfactory universality and accuracy. This study presents a novel approach to elucidating the mechanism and model prediction of inorganic salt inhibition of hydrate.

CO₂ fracturing is known as the best solution to improve the efficiency of the CO₂ replacement of natural gas hydrates, but the effect of CO₂ thickeners on CH₄-CO₂ replacement are barely noticed. In this work, the effect of four kinds of CO₂ thickener—including DL-Lactic acid, polyvinyl acetate, ethyl trifluoroacetate and octamethyl trisiloxane—on the CH₄-CO₂ replacement in quartz sand was measured thermodynamically and kinetically. The results show that the majority of the CO₂ thickeners had no effect on the equilibria of the CH₄ and CO₂ hydrates, except for DL-Lactic acid, where the temperature depression caused by the addition of 5.5 wt% DL-Lactic acid was about 0.52 and 0.48 K for the CH₄ and CO₂ hydrates, respectively. In the kinetic measurements, the CH₄-CO₂ replacement was promoted via the addition of the CO₂ thickeners, except DL-Lactic acid. The CO₂ thickeners were suggested to strengthen the CH₄-CO₂ replacement by enhancing the gas exchange in the pore space. Octamethyl trisiloxane, which could promote CH₄ recovery and CO₂ capture at a low concentration, was suggested to be an ideal CO₂ thickener for CH₄-CO₂ replacement.

We present the workflow for numerical reservoir simulation of supercritical multi-source and multi-component steam injection for offshore heavy oil development. We have developed unique techniques in a commercial reservoir simulator to implement the thermal properties of supercritical multi-source and multi-component steam, the pyrolysis chemical reactions, the temperature-dependent relative permeability, and the process of partially dissolving the sandstone rock to enhance the matrix permeability in a commercial reservoir simulator. Simulations are conducted on the type pattern reservoir model, which represents one of the heavy oil fields in CNOOC’s Bohai Bay oil field. Simulation input parameters are calibrated based on laboratory experiments conducted for supercritical multi-source and multi-component steam injection. Simulation results have shown clear improvements in injecting supercritical multi-source and multi-component steam in offshore heavy oil reservoirs compared to the normal steam injection process using subcritical steam. This serves as a workflow for implementing a numerical simulation of the novel supercritical multi-source and multi-component steam injection recovery process.

Investigations into the production of gas hydrates from marine sediments have demonstrated that commercial viability necessitates a daily gas production rate of 130,000 to 200,000 m³. However, the second-round trial production in the South China Sea yielded only 28,700 m³/day, falling short of the rule-of-thumb for economic feasibility. Given the coexistence of natural gas hydrates (NGHs) and shallow gas in the subsurface reservoirs of the South China Sea, a co-production strategy (simultaneously exploiting NGHs and shallow gas) was proposed to reduce costs and enhance production efficiency. In this study, a large-scale, three-dimensional, multi-phase, and multi-component model was established based on the NGHs–shallow gas symbiotic system in the Qiongdongnan Basin. A dual horizontal well configuration was designed to extract NGHs from the hydrate-bearing layer and natural gas from the underlying shallow gas layer. Co-production via dual horizontal wells expanded the hydrate dissociation zone from the near-wellbore region to deeper strata, particularly enhanced the dissociation of NGHs in the region between the two horizontal wells. By the 10th year of simulation, the peak and cumulative volume rate of CH₄ released from hydrate dissociation increased to 3.52 and 1.45 times under the co-production scenario, resulting in a 2.4-fold improvement in NGH recovery efficiency. Sensitivity analyses of bottom hole pressure and length of the horizontal intervals revealed that reducing bottom hole pressure significantly improved the daily and accumulative gas production from hydrate-bearing reservoirs. The length of horizontal intervals emerged as a critical factor influencing the dissociation of NGHs, whereas it had negligible impact on gas production from shallow gas reservoir with satisfied permeability. This study provides insights into optimizing the development of marine hydrate resources via integrated exploitation strategies.