(154c) Lithologic Heterogeneity and Focused Fluid Flow Governing Gas Hydrate Distribution in Marine Sediments
AIChE Spring Meeting and Global Congress on Process Safety
2012
2012 Spring Meeting & 8th Global Congress on Process Safety
1st International Conference on Upstream Engineering and Flow Assurance
The Future Wave - Graduate Students Session
Thursday, April 5, 2012 - 9:00am to 9:30am
Solid gas hydrates can form when low molecular weight gas molecules and water combine at relatively high gas concentrations, high pressures, low temperatures, and low salinity conditions. These conditions are present along many continental margins (as well as in permafrost environments) where hydrocarbon gases, especially CH4, accumulate in sediment pore space within a finite depth interval known as the gas hydrate stability zone (GHSZ). While the amount and distribution of marine gas hydrates remain uncertain, they may constitute a potential energy source, a deep-water geohazard, and an important component of the global carbon cycle.
Previous numerical models have coupled mass, momentum and energy transport equations to obtain steady-state solutions for gas hydrate distribution in marine sediments. These homogeneous 1-D models provide first-order insights on hydrate occurrence, but do not capture the complexity and heterogeneity observed in natural gas hydrate systems. Numerous studies have shown that gas hydrate and free gas accumulation in marine sediments is highly heterogeneous at the m-scale, which complicates views on their formation. Fracture network systems and dipping permeable layers are common heterogeneities in natural gas hydrate settings; these localize flow, resulting in accumulation of localized, concentrated hydrate deposits. To incorporate these heterogeneous features, lateral fluid flow and to broaden our knowledge of primary controls of hydrate concentration and distribution, we extend our previous 1-D model to two dimensions.
We develop a 2-D, heterogeneous sedimentation-fluid flow model that tracks gas hydrate accumulation over geologic time scales. Simulations with a vertical fracture network, which extends through the gas hydrate stability zone and has permeability 100 times greater than the surrounding shale formation, show that focused fluid flow causes higher hydrate (25-55%) and free gas saturation (30-45%) within the fracture network compared to the surrounding, lower permeability shale. Systems with high permeability, dipping sand layers also show localized, elevated saturations of hydrate (60%) and free gas (40%) within the sand layers due to focused fluid flow.
Permeability anisotropy, with a vertical to horizontal permeability ratio on the order of 10-2, enhances hydrate concentrations within high permeability conduits because anisotropy enhances transport of methane-charged fluid to high permeability conduits. Our two-dimensional (2-D), heterogeneous models quantify how focused fluid flow through high permeability zones affects local hydrate accumulation and saturation. We also show increased fluid flux and deep source methane input result in enhanced concentrations of hydrate and free gas, and also increase the flow focusing effects. From our 2-D results, we determine that the hydrate and free gas saturations can be characterized by the local Peclet number (localized, focused, advective flux relative to diffusion); which is consistent with Peclet number (net fluid flux relative to diffusion) characterization in one-dimensional (1-D) systems. This characterization suggests that even in lithologically complex systems, local hydrate and free gas saturations can be characterized by basic parameters (local flux and diffusivity). We intend to adapt our generalized model to specific field examples such as Walker Ridge in the Gulf of Mexico where enhanced hydrate saturation is noted in dipping sand layers.