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In marine continental margins, high saturations of natural gas hydrate are observed within the gas hydrate stability zone, but the gas migration pathways to the hydrate reservoir are not often clear. We focus on a site in Green Canyon Block 955 (GC 955) in the Gulf of Mexico, where gas hydrate occurs in a 35 m-thick reservoir with saturations of 79-93% in numerous centimeter- to decimeter-thick sandy silt layers and little to no gas hydrate in the interbedded cm to decimeter-thick clayey silt layers. Different datasets (well logging, coring, and seismic data) suggest different types of potential methane migration mechanisms. For example, relatively high particulate organic carbon content in the reservoir and the microbial methane source indicated by gas chromatography and methane isotopes suggest gas might be made locally and migration could occur through dissolved methane sources or water advection. In contrast, the visible deeply rooted faults intersecting the gas hydrate reservoir and the gas pockets adjacent to the faults on seismic data suggest that free gas may migrate directly into the reservoir. We tested three different mechanisms to form gas hydrate at GC 955: short-range methane diffusion, short-range methane diffusion coupled with upward water advection, and free gas flow. The 1-D and 2-D numerical models show that both the short-range migration and the upward water advection are not enough to form high saturations gas hydrate at GC 955, and that free gas flow is required to form the high saturations of gas hydrate observed at GC 955.

The University of Texas Hydrate Pressure Coring Expedition (UT-GOM2-1) recovered cores at near in situ formation pressures from a gas hydrate reservoir composed of sandy silt and clayey silt beds in Green Canyon Block 955 in the deep-water Gulf of Mexico. The expedition results are synthesized and linked to other detailed analyses presented in this volume. Millimeter- to meter-scale beds of sandy silt and clayey silt are interbedded on the levee of a turbidite channel. The hydrate saturation (the volume fraction of the pore space occupied by hydrate) in the sandy silts ranges from 79% to 93%, and there is little to no hydrate in the clayey silt. Gas from the hydrates is composed of nearly pure methane (99.99%) with less than 400 ppm of ethane or heavier hydrocarbons. The δ13C values from the methane are depleted (−60‰ to −65‰ Vienna Peedee belemnite), and it is interpreted that the gases were largely generated by primary microbial methanogenesis but that low concentrations of propane or heavier hydrocarbons record at least trace thermogenic components. The in situ pore-water salinity is very close to that of seawater. This suggests that the excess salinity generated during hydrate formation diffused away because the hydrate formed slowly or because it formed long ago. Because the sandy silt deposits have high hydrate concentration and high intrinsic permeability, they may represent a class of reservoir that can be economically developed. Results from this expedition will inform a new generation of reservoir simulation models that will illuminate how these reservoirs might be best produced.

We explore the petrophysical behavior of the two interbedded lithofacies (sandy silt and clayey silt) that constitute the Green Canyon Block 955 hydrate reservoir in the deep-water Gulf of Mexico by performing experiments on reconstituted samples of the reservoir material. Sandy silts reconstituted to the in situ porosity have a permeability of 11.8 md (1.18 × 10−14 m2), which is similar to the intrinsic permeabilities measured in intact cores from hydrate reservoirs of similar grain size offshore Japan (Nankai Trough) and offshore India. Reconstituted clayey silts have a much lower intrinsic permeability of 3.84 × 10−4 md (3.84 × 10−19 m2) at the in situ stress. The reconstituted sandy silt is less compressible than the clayey silt. Mercury injection capillary pressure measurements demonstrate that the largest pores with the clayey silt are still smaller than the pores remaining after 90% hydrate saturation in sandy silt. We interpret that the methane solubility in pores of clayey silt is always less than that necessary to form hydrate, which explains why no hydrate is present in the clayey silt. We upscale the reservoir properties to estimate the behavior of interbedded sandy silt and clayey silt. We find the upscaled intrinsic horizontal and vertical permeabilities for the entire reservoir interval are 8.6 md (8.6 × 10−15 m2) and 1.4 × 10−3 md (1.4 × 10−18 m2). We estimate that during reservoir production, a maximum vertical strain of approximately 12% will result. Ultimately, this study will inform reservoir simulation models with petrophysical properties at scales of both individual lithofacies and reservoir formation.