Rock-Eval pyrolysis and the biomarker composition of organic matter were systematically studied in hydrate-bearing sediments from the Shenhu area, South China Sea. The n-alkane distribution patterns revealed that the organic matter in the sediments appeared to originate from mixed sources of marine autochthonous input, terrestrial higher plants, and ancient reworked organic matter. The low total organic carbon contents (average < 0.5%) and the low hydrogen index (HI, <80 mg HC/g TOC) suggested the poor hydrocarbon-generation potential of the deposited organic matter at a surrounding temperature of <20 °C in unconsolidated sediments. The abnormally high production index and the fossil-originated unresolved complex mixture (UCM) accompanied by sterane and hopane of high maturity indicated the contribution of deep hydrocarbon reservoirs. Preliminary oil-to-source correlation for the extracts implied that the allochthonous hydrocarbons in the W01B and W02B sediments might have originated from the terrestrial source rocks of mature Enping and Wenchang formations, while those of W03B seem to be derived from more reduced and immature marine source rocks such as the Zhuhai formation. The results of the organic extracts supported the previous identification of source rocks based on the isotopic composition of C₂₊ hydrate-bound gases. The biomarker of methanogens, squalane, was recognized in the sediments of this study, possibly suggesting the generation of secondary microbial gases which are coupled with the biodegradation of the deep allochthonous hydrocarbons.

Molecular dynamics simulations were performed to study the effects of temperatures, pressures, and methane mole fractions on the generation behaviors, dynamic properties, and interfacial structures of methane gas bubbles. Methane gas bubbling can be promoted by high temperatures and high mole fractions of methane, which come from the generation of larger methane clusters in solution. Bubbles were found to be highly dynamic, with more methane molecules exchanging between bubbles and the surrounding solution at high pressures and in systems with high mole fractions of methane. The interfacial structures between bubbles and the surrounding solution were rough at a molecular level, and the roughness of the outermost methane and water molecules was high at high temperatures, low pressures, and in systems with high methane mole fractions. The dissolution of methane molecules depended on the interactions between the outermost methane and water molecules, which would become stronger with decreasing temperatures, increasing pressures, and decreasing methane mole fractions. The results obtained can help in understanding both the generation behaviors of bubbles when gas hydrates decompose and the re-nucleation behaviors of gas hydrates in the presence of bubbles.

Deepwater natural gas hydrate (NGH) exploration faces environmental and economic challenges due to the conventional seabed discharge of drilling mud. To address this, we developed an improved riserless mud recovery (RMR) system using hybrid risers to create a stable, decoupled circulation pathway. This innovative design fulfils three key operational needs: (1) closed-loop drilling fluid circulation with dual-gradient control, (2) completion fluid and test production returns, and (3) mechanical decoupling between the floating platform and subsea riser string. Numerical analysis shows that the system maintains operational stability under wave loading while effectively isolating seabed equipment from platform motion. Simulation results indicate that optimal performance requires a top tension ratio exceeding 1.5 and a submersion depth of 150–250 m, achieving a 70–80% reduction in drilling fluid consumption with full recovery capabilities. The hybrid riser-based RMR system provides a practical solution for sustainable NGH development, offering superior water depth adaptability for both drilling and completion operations in deepwater environments.

Natural gas hydrate is widely distributed, shallow-buried, clean, and pollution-free and has enormous reserves, it is regarded as the alternative clean energy source in the oil and gas field with the most potential. Pressure coring is the only way to drill for gas hydrate core on the surface under in situ conditions, which is of great value for analyzing its occurrence conditions and reserves comprehensively. Based on this, a new wireline pressure coring system (WPCS) with a ball valve seal was designed and developed in this paper; it was applied in the deep sea for the first time in the South China Sea hydrate survey voyage of the Guangzhou Marine Geological Survey (GMGS). A total of 15 runs of deep-sea gas hydrate drilling and coring applications were carried out, and they tested well. The experimental water depth was 1700–1800 m, and the coring depth below the seafloor was about 100–150 m. The formation consisted of sandy hydrate and argillaceous hydrate. The results showed the following. (1) The success rate of ball valve turn-over could reach almost 100% in the argillaceous hydrate reservoir, although there are some isolated cases of pressure relief. Meanwhile, drilling in the sandy hydrate reservoir, the success rate was only 54.55%. (2) When drilling in the argillaceous hydrate reservoir, the core recovery rate could reach 80%, while in the sandy hydrate reservoir, it was almost 0%. In practice, the sandy formation with gas hydrate is stiff to drill compared to the performance in argillaceous formations. After our analysis, it was believed that the ball valve and core tube could be easily plugged by sand debris during the sampling of sandy hydrate formation. Moreover, the sandy core is easily plugged into the core liner because of the high friction of sand grains in clearance. (3) The pressure-holding effect of the core drilling tool was related to the formation of hydrate, the sealing form of the ball valve, and the environmental pressure. Sandy hydrate formations often caused the ball valve to jam, while the muddy hydrate formation did not. The research results of this paper have reference value for the further optimization of the WPCS structure, the optimization of drilling parameters, and the design parameters of the ball valve structure, which could be better used for the pressure coring of gas hydrate and subsequent research work in the future.

The degree and amount of sand production in hydrate reservoirs is related to the selection of stable production processes, but there is currently a lack of quantitative sand production prediction research using real logging data and formation samples from hydrate reservoirs. To reveal the dynamic change characteristics of in-situ reservoirs during hydrate decomposition, and explore quantitative prediction methods for guiding production practice, it is conducted a series of numerical simulations and quantitative prediction experiments. The numerical simulations are carried out using different sand-out prediction methods by using hydrate logging data during drilling, while quantitative prediction experiments of water production and sand-out are carried out based on in-situ reservoir samples. Our experiments indicate that hydrate mining is facing a serious risk of sand-out. The particle transport in the reservoir changes from “large-channel seepage” to “umbrella seepage” and then to “uniform fine flow” as the replacement flow rate decreases. A quantitative prediction model for water and sand production is also established. As a result, our study can provide support for the advancement of technology for long-term stable production and sand control of hydrates, laying the groundwork for developing a stable production plan for natural gas hydrates in offshore areas and determining the optimal depressurisation method.

The efficient extraction of natural gas from marine natural gas hydrate (NGH) reservoirs is challenging, due to their low permeability, high hydrate saturation, and fine-grained sediments. Hydraulic fracturing has been proven to be a promising technique for improving the permeability of these unconventional reservoirs. This study presents a comprehensive triaxial experimental investigation of the fracturing behavior and fracture initiation mechanisms of NGH-bearing sediments, using large-scale ice-saturated synthetic cubic models. The experiments systematically explore the effects of key parameters, including the injection rate, fluid viscosity, ice saturation, perforation patterns, and in situ stress, on fracture propagation and morphology. The results demonstrate that at low fluid viscosities and saturation levels, transverse and torsional fractures dominate, while longitudinal fractures are more prominent at higher viscosities. Increased injection rates enhance fracture propagation, generating more complex fracture patterns, including transverse, torsional, and secondary fractures. A detailed analysis reveals that the perforation design significantly influences the fracture direction, with 90° helical perforations inducing vertical fractures and fixed-plane perforations resulting in transverse fractures. Additionally, a plastic fracture model more accurately predicts fracture initiation pressures compared to traditional elastic models, highlighting a shift from shear to tensile failure modes as hydrate saturation increases. This research provides new insights into the fracture mechanisms of NGH-bearing sediments and offers valuable guidance for optimizing hydraulic fracturing strategies to enhance resource extraction in hydrate reservoirs.