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Can We Accurately Model Fluid Flow in Shale? Print
Thursday, 03 January 2013 00:00

Over 20 trillion cubic meters of natural gas are trapped in shale, but many shale oil and gas producers still use models of underground fluid flow that date back to the heyday of easy-to-tap gas and liquid crude. The source of shale oil and gas is kerogen, an organic material in the shale, but until now kerogen hasn’t been incorporated in mathematical models of shale gas reservoirs. Paulo Monteiro, Chris Rycroft, and Grigory Isaakovich Barenblatt, with the Computational Research Division and the Advanced Light Source, recently modeled how pressure gradients in the boundary layer between kerogen inclusions and shale matrices affect productivity and can model reservoir longevity.

Real the Full Article

The model developed by Monteiro, Rycroft, and Barenblatt posits a porous, fissurized matrix (I) with enough permeability to be treated by standard fluid mechanics, as well as a kerogen inclusion (II) with very low permeability. During mining, a boundary layer of flow forms in the kerogen, as shown by the textured brown strip. Fluid moves out of the inclusion, indicated by the red arrows. The evolution of the boundary layer, analyzed along the coordinate labeled X, is key to the rate and longevity of the formation’s productivity.