Methane gas hydrates, crystalline inclusion compounds formed from methane and water, are found in marine continental margin and permafrost sediments worldwide. This article reviews the current understanding of phenomena involved in gas hydrate formation and the physical properties of hydrate‐bearing sediments. Formation phenomena include pore‐scale habit, solubility, spatial variability, and host sediment aggregate properties. Physical properties include thermal properties, permeability, electrical conductivity and permittivity, small‐strain elastic P and S wave velocities, shear strength, and volume changes resulting from hydrate dissociation. The magnitudes and interdependencies of these properties are critically important for predicting and quantifying macroscale responses of hydrate‐bearing sediments to changes in mechanical, thermal, or chemical boundary conditions. These predictions are vital for mitigating borehole, local, and regional slope stability hazards; optimizing recovery techniques for extracting methane from hydrate‐bearing sediments or sequestering carbon dioxide in gas hydrate; and evaluating the role of gas hydrate in the global carbon cycle.

Summary: The current paper complements the Moridis et al. (2009) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas-hydrate (GH) petroleum system; to discuss advances, requirements, and suggested practices in GH prospecting and GH deposit characterization; and to review the associated technical, economic, and environmental challenges and uncertainties, which include the following: accurate assessment of producible fractions of the GH resource; development of methods for identifying suitable production targets; sampling of hydrate-bearing sediments (HBS) and sample analysis; analysis and interpretation of geophysical surveys of GH reservoirs; well-testing methods; interpretation of well-testing results; geomechanical and reservoir/well stability concerns; well design, operation, and installation; field operations and extending production beyond sand-dominated GH reservoirs; monitoring production and geomechanical stability; laboratory investigations; fundamental knowledge of hydrate behavior; the economics of commercial gas production from hydrates; and associated environmental concerns.

The physical properties of gas hydrate‐bearing sediments depend on the volume fraction and spatial distribution of the hydrate phase. The host sediment grain size and the state of effective stress determine the hydrate morphology in sediments; this information can be used to significantly constrain estimates of the physical properties of hydrate‐bearing sediments, including the coarse‐grained sands subjected to high effective stress that are of interest as potential energy resources. Reported data and physical analyses suggest hydrate‐bearing sands contain a heterogeneous, patchy hydrate distribution, whereby zones with 100% pore‐space hydrate saturation are embedded in hydrate‐free sand. Accounting for patchy rather than homogeneous hydrate distribution yields more tightly constrained estimates of physical properties in hydrate‐bearing sands and captures observed physical‐property dependencies on hydrate saturation. For example, numerical modeling results of sands with patchy saturation agree with experimental observation, showing a transition in stiffness starting near the series bound at low hydrate saturations but moving toward the parallel bound at high hydrate saturations. The hydrate‐patch size itself impacts the physical properties of hydrate‐bearing sediments; for example, at constant hydrate saturation, we find that conductivity (electrical, hydraulic and thermal) increases as the number of hydrate‐saturated patches increases. This increase reflects the larger number of conductive flow paths that exist in specimens with many small hydrate‐saturated patches in comparison to specimens in which a few large hydrate saturated patches can block flow over a significant cross‐section of the specimen.

Injection of carbon dioxide (CO₂) into saline aquifers confined by low- permeability cap rock will result in a layer of CO₂ overlying the brine. Dissolution of CO₂ into the brine increases the brine density, resulting in an unstable situation in which more-dense brine overlies less-dense brine. This gravitational instability could give rise to density-driven convection of the fluid, which is a favorable process of practical interest for CO₂ storage security because it accelerates the transfer of buoyant CO₂ into the aqueous phase, where it is no longer subject to an upward buoyant drive. Laboratory flow visualization tests in transparent Hele-Shaw cells have been performed to elucidate the processes and rates of this CO₂ solute-driven convection (CSC). Upon introduction of CO₂ into the system, a layer of CO₂-laden brine forms at the CO₂-water interface. Subsequently, small convective fingers form, which coalesce, broaden, and penetrate into the test cell. Images and time-series data of finger lengths and wavelengths are presented. Observed CO₂ uptake of the convection system indicates that the CO₂ dissolution rate is approximately constant for each test and is far greater than expected for a diffusion-only scenario. Numerical simulations of our system show good agreement with the experiments for onset time of convection and advancement of convective fingers. There are differences as well, the most prominent being the absence of cell-scale convection in the numerical simulations. This cell-scale convection observed in the experiments may be an artifact of a small temperature gradient induced by the cell illumination.