Natural gas hydrate (NGH) deposits represent a vast and clean energy source. However, sustainable gas production from these resources remains an unsolved technical problem due to potential geohazards and climate challenges. A critical issue in this regard is the difficulty of obtaining in situ samples, which are essential for detailed laboratory studies of NGH’s geomechanical and chemical behavior for safe and green gas production after hydrate dissociation. Currently, the retrieval of representative samples from NGH reservoirs is hindered by significant technological limitations and high costs. Consequently, laboratory-synthesized gas hydrate-bearing sediment (HBS) samples are crucial for controlled research purposes and validating numerical simulation models and are used in the majority of research studies. With this in mind and considering the complexity of synthesizing HBS samples, this study comprehensively reviews different methods of synthesizing gas hydrates in porous media, including excess-gas, excess-water, dissolved-gas, spray, bubble injection, and hybrid techniques. Each method produces distinct hydrate morphologies (e.g., pore-filling, cementing, grain-coating, etc.) and saturation levels, with trade-offs in speed, uniformity, reproducibility, and ease of control. Furthermore, the current review details the synergic application of non-invasive characterization techniques, i.e., X-ray Computed Tomography (CT) and Nuclear Magnetic Resonance (NMR), in studying gas hydrates. CT provides high-resolution three-dimensional (3D) structural images of pore geometry and hydrate distribution, while NMR/MRI (Magnetic Resonance Imaging) quantifies fluid saturations and tracks hydrate formation/dissociation dynamics in real time. The synergistic use of CT and NMR offers a powerful multimodal approach, overcoming individual limitations such as CT’s poor hydrate–water contrast detection and NMR’s indirect hydrate inference, which could help in the sustainable synthesis of particular hydrate morphologies. Finally, the critical analysis of current technological challenges or gaps and also the emerging trends and future directions in the study of HBS, including advanced imaging techniques, AI-assisted analysis, and standardization efforts, etc., are discussed. It was found that the selection of the most appropriate method for natural gas hydrate synthesis is mostly task-specific, and the emerging technologies have facilitated the synthesis of HBS samples with more precise control of morphology, saturation, etc. This review provides the required insights for sustainable synthesis and characterization of hydrate-bearing sediments samples and serves sustainable gas production from natural gas hydrate reservoirs.

Coalbed methane (CBM) reservoirs exhibit complex deformation behaviors during gas production, and reservoir rock compressibility plays a critical role in controlling permeability evolution and production performance. With the increasing development of deep CBM resources, a comprehensive understanding of different compressibility behaviors under complex geological conditions is essential for accurate reservoir evaluation and sustainable gas production. This study systematically reviews the recent advances in the characterization of the compressibility phenomena in CBM reservoirs, including bulk compressibility, fracture compressibility, cleat compressibility, pore-volume compressibility, matrix compressibility, and matrix shrinkage effect. The mechanisms, experimental characterization methods, and theoretical models associated with each type of compressibility are discussed and compared. Existing studies indicate that fracture and cleat closure can substantially reduce permeability, while pore-volume compression varies with coal rank, pore–fracture structure, and loading conditions. Meanwhile, gas desorption-induced matrix shrinkage can partially counteract stress-induced fracture closure and contribute to permeability recovery during the later stage of CBM production. Various experimental techniques, including triaxial mechanical testing, mercury intrusion porosimetry, nuclear magnetic resonance, X-ray computed tomography (X-ray CT), and in situ monitoring methods, have been widely applied to characterize reservoir compressibility and the resultant pore–fracture space evolution. Classical models have provided fundamental insights into the relationship between compressibility and permeability evolution. The research findings reveal that, despite significant progress, current studies still mainly focus on individual compressibility behaviors, while the coupled evolution mechanisms among different types of compressibility remain insufficiently understood. In addition, the effects of deep-reservoir conditions, including high temperature and high stress on compressibility evolution require further investigation. Future research should also focus on the multiscale and multiphysics characterization of coupled compressibility behaviors, the development of dynamic compressibility evaluation methods, and the integration of advanced imaging techniques and data-driven approaches to improve permeability prediction for CBM reservoirs.