Steady State Permeability Measurements in Shales

Characterizing matrix permeability in shale formations is vital to determining the long term productivity of a reservoir as well as determining the optimal completion design. Permeability of shales lies in the nanodarcy (six orders of magnitude lower than conventional reservoir formations) range and the pore structure of these rocks is often complex, characterized by mixed wettability and presence of organics. In this work, we find that the permeability of shales is dependent on the pore fluid used for estimation. Gas (nitrogen) and liquid (dodecane) permeability measurements carried out on the same core plug successively can differ by up to a factor of 4. Gas and liquid permeability measurements were made on 16 samples from Bakken, Eagle Ford, Wilcox and Wolfcamp formations. Higher TOC samples correspond to higher gas to liquid permeability ratios, exacerbating the effect of pore fluid on the permeability measurement. Contrary to some published literature, permeability creep, i.e. the change of permeability as a function of time at constant net effective stress has been observed to be insignificant. The laboratory measurement time for permeability tests can thus be minimized. This observation also suggests minimal long-term loss of production due to permeability creep. Creep measurements were made on three samples using nitrogen (on a Bakken sample) and dodecane (Wolfcamp samples). With respect to temperature effects, permeability measurements performed at 158 °F on shale samples from Marcellus, Vaca Muerta and Wolfcamp formations indicates insignificant (