Beschreibung: Results from two recent field trials, onshore in the Alaska permafrost and in the Nankai Trough offshore Japan, suggest that natural gas could be produced from marine gas hydrate reservoirs at compatible yields and rates. However, both field trials were accompanied by different technical issues, the most striking problems resulting from un-predicted geomechanical behaviour, sediment destabilization and catastrophic sand production. So far, there is a lack of experimental data which could help to understand relevant mechanisms and triggers for potential soil failure in gas hydrate production, to guide model development for simulation of soil behaviour in large-scale production, and to identify processes which drive or, further, mitigate sand production. We use high-pressure flow-through systems in combination with different online and in situ monitoring tools (e.g. Raman microscopy, MRI) to simulate relevant gas hydrate production scenarios. Key components for soil mechanical studies are triaxial systems with ERT (Electric resistivity tomography) and high-resolution localstrain analysis. Sand production control and management is studied in a novel hollow-cylinder-type triaxial setup with a miniaturized borehole which allows fluid and particle transport at different fluid injection and flow conditions. We further apply a novel large-scale high-pressure flow-through triaxial test system equipped with μ-CT to evaluate soil failure modes and triggers relevant to gas hydrate production and slope stability. The presentation will emphasize an in-depth evaluation of our experimental approach, and it is our concern to discuss important issues of translating laboratory results to gas hydrate reservoirs in nature. We will present results from high-pressure flow-through experiments which are designed to systematically compare soil mechanical behaviour of gas hydrate-bearing sediments in relevant production scenarios focusing on depressurization and CO2 injection. Experimental datasets are analyzed based on numerical models which are able to simulate coupled process dynamics during gas hydrate formation and gas production.

Beschreibung: The presence of gas hydrates (GHs) increases the stiffness and strength of marine sediments. In elasto‐plastic constitutive models, it is common to consider GH saturation (Sh) as key internal variable for defining the contribution of GHs to composite soil mechanical behavior. However, the stress‐strain behavior of GH‐bearing sediments (GHBS) also depends on the microscale distribution of GH and on GH‐sediment fabrics. A thorough analysis of GHBS is difficult, because there is no unique relation between Sh and GH morphology. To improve the understanding of stress‐strain behavior of GHBS in terms of established soil models, this study summarizes results from triaxial compression tests with different Sh, pore fluids, effective confining stresses, and strain histories. Our data indicate that the mechanical behavior of GHBS strongly depends on Sh and GH morphology, and also on the strain‐induced alteration of GH‐sediment fabrics. Hardening‐softening characteristics of GHBS are strain rate‐dependent, which suggests that GH‐sediment fabrics dynamically rearrange during plastic yielding events. We hypothesize that rearrangement of GH‐sediment fabrics, through viscous deformation or transient dissociation and reformation of GHs, results in kinematic hardening, suppressed softening, and secondary strength recovery, which could potentially mitigate or counteract large‐strain failure events. For constitutive modeling approaches, we suggest that strain rate‐dependent micromechanical effects from alterations of the GH‐sediment fabrics can be lumped into a nonconstant residual friction parameter. We propose simple empirical evolution functions for the mechanical properties and calibrate the model parameters against the experimental data. Plain Language Summary Gas hydrates (GHs) are crystalline‐like solids, which are formed from natural gas molecules and water at high pressure and low temperature. GHs, and particularly methane hydrates, are naturally abundant in marine sediments. It is known that the presence of GH increases the mechanical stiffness and strength of sediments, and there is strong effort in analyzing and quantifying these effects in order to understand potential risks of sediment destabilization or slope failure. Based on our experimental results from high‐pressure geotechnical studies, we show that not only the initial amount and distribution of GH are important for the increased strength of GH‐bearing sediments but also the dynamic rearrangement of GH‐sediment fabrics during deformation characterizes the stress‐strain response and enables strength recovery after failure. We propose that different microstructural mechanisms contribute to this rearrangement and strength recovery of GH sediment. However, we consider these complicated processes in a simplified manner in an improved numerical model, which can be applied for geotechnical risk assessment on larger scales.

Beschreibung: Transport of fluids in gas hydrate bearing sediments is largely defined by the reduction of the permeability due to gas hydrate crystals in the pore space. Although the exact knowledge of the permeability behavior as a function of gas hydrate saturation is of crucial importance, state-of-the-art simulation codes for gas production scenarios use theoretically derived permeability equations that are hardly backed by experimental data. The reason for the insufficient validation of the model equations is the difficulty to create gas hydrate bearing sediments that have undergone formation mechanisms equivalent to the natural process and that have well-defined gas hydrate saturations. We formed methane hydrates in quartz sand from a methane-saturated aqueous solution and used Magnetic Resonance Imaging to obtain time-resolved, three-dimensional maps of the gas hydrate saturation distribution. These maps were fed into 3-D Finite Element Method simulations of the water flow. In our simulations, we tested the five most well-known permeability equations. All of the suitable permeability equations include the term (1-SH)n, where SH is the gas hydrate saturation and n is a parameter that needs to be constrained. The most basic equation describing the permeability behavior of water flow through gas hydrate bearing sand is k = k0 (1-SH)n. In our experiments, n was determined to be 11.4 (±0.3). Results from this study can be directly applied to bulk flow analysis under the assumption of homogeneous gas hydrate saturation and can be further used to derive effective permeability models for heterogeneous gas hydrate distributions at different scales.