EFFECTS OF FLOW FOCUSING AND GEOLOGIC STRUCTURES ON GAS HYDRATE SATURATION AND DISTRIBUTION

We simulate the migration of water, dissolved methane, and free gas to understand the primary controls on natural gas hydrate saturation and distribution. Models of clay-dominated systems show that over thousands to millions of years, gas hydrate can occlude the pore system, which results pressure build-up and hydraulic fracturing. These fractures then fill with hydrate. In clay systems with silt or sand inter-layers, our models simulate how pore-filling hydrate dominates permeable inter-layers and fracture-filling hydrate dominates low permeability layers. These models help explain numerous observations of heterogeneous hydrate accumulation. Simulations with permeability heterogeneity and anisotropy facilitate further characterization of natural gas hydrate deposits. Steady-state simulations with a vertical fracture network (fracture permeability = 100 times matrix permeability) show how focused fluid flow increases hydrate (25-55%) and free gas saturation (30-45%) within the fractures as compared to the shale matrix. Localized flow focusing in high permeability, dipping sand layers locally increases saturations of hydrate (60%) and free gas (40%). These 2D simulations emphasize the importance of local methane (dissolved or free gas) flux on local hydrate saturations and distribution. The fracturing process explains some details of the controls on hydrate habit. Through analysis of the fluid fluxes in 2D systems, we show that a local Peclet number characterizes the local hydrate and free gas saturations, just as the Peclet number characterizes hydrate saturations in 1D, homogeneous systems. To illustrate the importance of local flux on simple and complex natural hydrate systems we use our model to simulate accumulation and distribution of hydrates for four distinct hydrate settings: Blake Ridge, Hydrate Ridge, the Gulf of Mexico, and the Krishna-Godavari Basin.