What exactly drives fluid flow in a Shale Gas Reservoir?
If the mean pore-size of an ‘extremely fine-grained’, ‘nano-scale pore-structure’ of a ‘shale gas reservoir’ remain to be lesser than ‘50 microns’ (associated either with kerogen Types II or III), while, if it’s associated mean ‘matrix permeability’ remain to be lesser than ‘one micro-Darcy’, then, what is the basis on which the fluid transport mechanism of shale-gas – within such reservoir - would be dictated either (a) to be ‘Knudsen diffusion’; or, (b) to be ‘surface diffusion’; or, (c) to be a combination of ‘free molecular diffusion’, ‘surface diffusion’; and ‘Knudsen diffusion’ using the concept of ‘effective diffusion coefficient’ (multi-diffusion) – upon getting ‘adsorbed methane’ - desorbed from the organic-rich shale surfaces?
Is there a clarity on the way, by which both ‘adsorption’ and ‘desorption’ of ‘shale gas’ takes place as a function of ‘mean pore-size’ (or, multi-porosity) and ‘mean matrix permeability’ (or, multi-permeability)?
Feasible to deduce the ‘rate at which’ the shale gas gets ‘adsorbed’ - as well as - that gets ‘desorbed’ on a larger field-scale? Would it depend on ‘total organic content’ also, in addition to its dependence on reservoir pressure and temperature?
Feasible to comment on the ‘restructuring of pore-geometry’ ‘before’ and ‘after’ treating such shale gas reservoirs by ‘stimulation’ process?
With ultra-low permeable shale gas reservoirs, how do we deduce a conclusion on the ‘restructuring of pore geometries’, in case, if the ‘transient regime’ keeps continuing across the ‘entire life of the well’?
If not, how do we dictate the resulting diffusive mode of shale-gas transport process (free molecular diffusion; Knudsen diffusion, surface diffusion)?
For that matter, could we use, even, non-linear fluid flow equation – in order to estimate the spatial (radial) and temporal evolution of pseudo-pressure within a shale-gas reservoir (a) in the presence of ‘slip-flow’; ‘surface/Knudsen diffusion’; or, (b) in the absence of an explicit ‘gravity and capillary forces’; or, (c) when the ‘surface diffusive flux’ remains dominant over viscous and gravity effects? Under such circumstances, whether the consideration of ‘poro-elasticity (porosity evolution)’; or, ‘entropy’; or, ‘vorticity’ would really be meaningful?
Even during ‘horizontal drilling’ and ‘multi-stage hydraulic fracturing’, to what extent, the ‘artificially induced’ ‘fracture network’ will be able to “retain” the ‘resultant conductivity’ ‘ between high-permeable fractures and low-permeable matrix’?
Upon introducing all assumptions and simplifications, can we linearly correlate the ‘adsorbed gas’ to the ‘total gas production’?
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