Abstract:The recovery of natural gas from CH 4 -hydrate deposits in sub-marine and sub-permafrost environments through injection of CO 2 is considered a suitable strategy towards emission-neutral energy production. This study shows that the injection of hot, supercritical CO 2 is particularly promising. The addition of heat triggers the dissociation of CH 4 -hydrate while the CO 2 , once thermally equilibrated, reacts with the pore water and is retained in the reservoir as immobile CO 2 -hydrate. Furthermore, optimal reservoir conditions of pressure and temperature are constrained. Experiments were conducted in a high-pressure flow-through reactor at different sediment temperatures (2 °C, 8 °C, 10 °C) and hydrostatic pressures (8 MPa, 13 MPa). The efficiency of both, CH 4 production and CO 2 retention is best at 8 °C, 13 MPa. Here, both CO 2 -and CH 4 -hydrate as well as mixed hydrates can form. At 2 °C, the production process was less effective due to congestion of transport pathways through the sediment by rapidly forming CO 2 -hydrate. In contrast, at 10 °C CH 4 production suffered from local increases in permeability and fast breakthrough of the injection fluid, thereby confining the accessibility to the CH 4 pool to only the most prominent fluid channels. Mass and volume balancing of the collected gas and fluid stream identified gas mobilization as equally important process parameter in addition to the rates of methane hydrate dissociation and hydrate conversion. Thus, the combination of heat supply and CO 2 injection in one supercritical phase helps to overcome the mass transfer limitations usually observed in experiments with cold liquid or gaseous CO 2 .

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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.