Hydrate plugging is a hidden threat to the safe exploitation of oil and gas. Inorganic salts are widely used as thermodynamic inhibitors to effectively prevent the hydrate formation. This study uses a molecular dynamics method to explore the mechanism of the hydrate dissociation via inorganic salts on the micro-scale. We simulated the dissociating process of methane hydrate under different concentration series of NaCl, KCl and CaCl₂ solutions at 273 K, and analysed the changes of ionic structure, transport parameters and kinetic energy in the system of inorganic salt/hydrate. The simulation results successfully revealed the step-by-step dissociation of hydrate, and the differences in dissociation rates among the different inhibitors. The energy needed for hydrate dissociation alters for different inorganic solutions; the energy reaches maximum when KCl is the inhibitor, and lowest when the concentration of CaCl₂ exceeds 30% w/w. We calculated the coordination numbers of all components, including oxygen atoms, cations and anions, and also their diffusion coefficients; analysed the effects of the three inorganic salts on the simulated hydrate structure and its transport; in addition, investigated the mechanism of hydrate dissociation via inorganic salts.

Summary: CO2 huff ‘n’ puff is a promising enhanced oil recovery (EOR) technique for tight/shale reservoirs, also enabling CO2 geological storage. However, the effectiveness of this method can be significantly affected by the aqueous phase resulting from connate water and hydraulic fracturing. The mechanism underlying the influence of the aqueous phase on oil recovery during CO2 huff ‘n’ puff, as well as the corresponding stimulation methods in such scenarios, remain unclear and warrant further study. To investigate this, we utilized a nuclear magnetic resonance (NMR) instrument to track the movement of fluids during CO2 huff ‘n’ puff under water invasion conditions. The impact of the invaded aqueous phase on oil recovery was examined, and the impact of different treatment parameters was explored. The results show that the aqueous barrier formed by water invasion alters the pathway of CO2 diffusion to matrix oil. This alteration leads to a diminished concentration of CO2 in the oil phase, which, in turn, results in a substantial reduction in oil recovery. Consequently, the performance of CO2 huff ‘n’ puff is highly sensitive to the water phase. Nevertheless, the oil recovery dynamics in cyclic CO2 huff ‘n’ puff under water invasion exhibit distinctive patterns compared with those without water invasion. These differences manifest as notable low oil recovery in the first cycle, followed by a rapid increase in the second cycle. This behavior primarily arises from the expulsion of a significant portion of the invaded water from the macropores after the first cycle. However, the effectiveness of this mechanism is limited in micropores due to the challenging displacement of trapped water in such pores. Raising the injection pressure mainly boosts oil recovery in macropores, with minimal response in micropores. Yet, the achievement of miscibility does not lead to a substantial improvement in the CO2 huff ‘n’ puff performance, primarily due to the constraints imposed by the limited CO2 dissolution through molecular diffusion Additionally, we have proposed three stimulation mechanisms achieved by lengthening the soaking time under water invasion conditions. First, the prolonged soaking time increases the concentration of CO2 molecules that diffuse into the matrix oil. Second, it promotes the imbibition of the trapped water on the fracture surface into the deeper matrix to alleviate water blockage. Finally, the invaded water in macropores displaces oil in micropores by capillary force during the soaking period.

Natural gas hydrates (NGHs) are regarded as a new energy resource with great potential and wide application prospects due to their tremendous reserves and low CO₂ emission. Permeability, which governs the fluid flow and transport through hydrate-bearing sediments (HBSs), directly affects the fluid production from hydrate deposits. Therefore, permeability models play a significant role in the prediction and optimization of gas production from NGH reservoirs via numerical simulators. To quantitatively analyze and predict the long-term gas production performance of hydrate deposits under distinct hydrate phase behavior and saturation, it is essential to well-establish the permeability model, which can accurately capture the characteristics of permeability change during production. Recently, a wide variety of permeability models for single-phase fluid flowing sediment have been established. They typically consider the influences of hydrate saturation, hydrate pore habits, sediment pore structure, and other related factors on the hydraulic properties of hydrate sediments. However, the choice of permeability prediction models leads to substantially different predictions of gas production in numerical modeling. In this work, the most available and widely used permeability models proposed by researchers worldwide were firstly reviewed in detail. We divide them into four categories, namely the classical permeability models, reservoir simulator used models, modified permeability models, and novel permeability models, based on their theoretical basis and derivation method. In addition, the advantages and limitations of each model were discussed with suggestions provided. Finally, the challenges existing in the current research were discussed and the potential future investigation directions were proposed. This review can provide insightful guidance for understanding the modeling of fluid flow in HBSs and can be useful for developing more advanced models for accurately predicting the permeability change during hydrate resources exploitation.