Natural gas hydrate (NGH) has the huge exploitation potential for clean energy in the current world energy pattern. Its total organic carbon storage is about twice the sum of carbon content of oil, gas, and coal and hence attracts the attention of the world. China has carried out some gas hydrate exploitation works and delineation of three gas hydrate deposits whose reserve scale is over 100 billion cubic meters, and the NGH resource is abundant. The NGH reservoir in the South China Sea is of low porosity and permeability, is unconsolidated, has poor cementation, and is easy to fragment in hydrate production. On the one hand, the condition of low porosity and permeability around the well would severely reduce the production effect; on the other hand, the hydrate decomposition would more easily bring wellbore instability caused by stratum stress change. Therefore, to achieve safe and efficient exploitation of NGH, proper reservoir reconstruct technology needs to be chosen for enhancing the reservoir’s permeability and stability. This paper chose the Shenhu area of South China Sea as the research area, constructed the three-dimensional heterogeneous geological model of hydrate-bearing sediments which can be approximated realistically to depict, then used high-pressure jet grouting (HPJG) technology to reconstruct the hydrate reservoir, optimized the grouting hole direction, location, and spacing, and assessed the productivity increasing effect. The research results show the following: (a) Because of the higher hydrate saturation (SH) and lower permeability (k) around the well, the HPJG in the vertical direction was profitable for reservoir productivity. (b) Considering the heterogeneous SH and k in the horizontal direction, the HPJG in the front of the horizontal well was profitable for the reservoir productivity. (c) The HPJG spacing needs to be properly designed in combination with the absolute standard (V P), the relative standard (R GM), and the specific production index (J). (d) Under the conditions of this paper setting, the optimal HPJG reconstruction scheme is as follows: the HPJG in the vertical direction was arranged at the front of the horizontal well, and the spacing between the holes was 10 m. The productivity after reconstruction ranged up to 55.69% compared with before.

Marine natural gas hydrate (NGH) is an important source of energy for the future, while the experimental simulations on NGH production are rarely conducted in real marine sediments. This study employed the real sediments from South China Sea and put upward a method of remolding NGH sediments by hydrate formation after injecting water into a dry sediment with high-pressure methane gas. A 2 °C temperature increase was observed in the middle layer of the sediment due to the exothermic formation of hydrates. The production characteristics of NGH sediments with different moistures (28.3–73.7%) were evaluated by depressurization. A uniform decomposition stage during the production process was defined, and the apparent uniform decomposition rates in all cases were around 2.1 mmol/min. Intrinsic decomposition rate of hydrate crystal and limited heat transfer outside of sediments were likely to be the main deciding factors. When the sediment changed into the water-saturated condition, the excess water improved the transfer and greatly increased the decomposition rate of hydrates. In addition, the complex response of sediment temperatures to the pressure change, hydrate decomposition, heat transfer, as well as sometime ice formation and melting were analyzed from the perspectives of both thermodynamic and heat transfer. The results of this study are of great significance for future pilot production of real marine NGH.

Widely employed in hydrate exploitation, the single well method is utilized to broaden the scope of hydrate decomposition. Optimizing the well structure and production strategy is necessary to enhance gas recovery efficiency. Complex wells represented by the multilateral wells have great application potential in hydrate mining. This study focused on the impact of multilateral well production methods on productivity, taking the Nankai Trough in Japan as the study area. The spatial distribution of physical parameters such as porosity, permeability, and hydrate saturation in the Nankai Trough has significant heterogeneity. For model accuracy, the Sklearn machine learning and Kriging interpolation methods were used to construct a three-dimensional heterogeneous geological model to describe the structure and physical property parameters in the study area of the hydrate reservoir. The numerical simulation model was solved using the TOUGH + Hydrate program and fitted with the measured data of the trial production project to verify its reliability. Finally, we set the multilateral wells for hydrate high saturation area to predict the gas and water production of hydrate reservoir with different exploitation schemes. The main conclusions are as follows: ① The Sklearn machine learning and Kriging interpolation methods can be used to construct a three-dimensional heterogeneous geological model for limited site data, and the fitting effect of the heterogeneous numerical simulation model is better than that of the homogeneous numerical simulation model. ② The multilateral well method can effectively increase the gas production rate from the hydrate reservoir compared with the traditional single well method by approximately 8000 m3/day on average (approximately 51.8%). ③ In the high saturation area, the number of branches of the multilateral well were set to 2, 3, and 4, and the gas production rate was increased by approximately 51.8%, 52.5%, and 53.5%. Considering economic consumption, the number of branching wells should be set at 2–3 in the same layer.

CO2-EOR (Enhanced Oil Recovery) is a vital method to increase oil recovery while significantly lower greenhouse gas emissions. The near-miscible conditions are useful to improve displacement efficiency and oil recovery by CO2 injection. In this study, at the nearmiscible condition of 8MPa, 40°C, using X-ray microtomography (micro-CT), pore-scale interfacial characteristics can be obtained in the CO2-oil-glass beads system, such as wettability, which represents the tendency of fluids in the solid. A displacement of oil by CO2 was performed to examine the two-phase interfacial characteristics in the gas-oil-solid system. With the multiphase identification approach and in-situ spatial distribution of contact angle (𝜃𝜃), the 𝜃𝜃 at 5.5PV was nearly 66.99° at near-miscible conditions, which indicates an intermediate-wet system. With increasing injection pore volumes (PV) from 5.5PV to 16.4PV, the contact angle increases from 66.99° to 70.42°, indicating a decrease in the water-wet property. Although oil resides in pores of all sizes (big, medium, and small), gas often fills the larger pores. The interfacial curvature examination revealed that in-situ capillary pressure provides a distribution with an average value near zero. The rock performed a wettability reversal from a waterwet to an intermediate-wet condition. The knowledge of near-miscible two-phase flow is helpful to enhance oil recovery and storage efficiency.