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Abstract

DOI: 10.1306/01062019165

Petrophysical properties of the Green Canyon Block 955 hydrate reservoir inferred from reconstituted sediments: Implications for hydrate formation and production

Yi Fang,1 Peter B. Flemings,2 Hugh Daigle,3 Stephen C. Phillips,4 P. Kevin Meazell,5 and Kehua You6

1Institute for Geophysics, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; [email protected]
2Institute for Geophysics, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; Department of Geological Sciences, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; [email protected]
3Hildebrand Department of Petroleum and Geosystems Engineering, Cockrell School of Engineering, The University of Texas at Austin, Austin, Texas; [email protected]
4Institute for Geophysics, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; [email protected]
5Institute for Geophysics, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; Department of Geological Sciences, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; [email protected]
6Institute for Geophysics, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas; [email protected]

ABSTRACT

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.

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