Microstructural investigation of stress-dependent permeability in tight-oil rocks

Recent studies on several core-plug-scale samples from tight-oil reservoirs have demonstrated that such rocks can exhibit a substantial, irreversible permeability decline with increase in net confining stress. Because this effect closely follows the expected stress change during drawdown in the field, the origins of this phenomena, as well as a method to predict the magnitude relative to different rock types, is valuable information for reservoir management. To better understand this effect, we have undertaken a series of laboratory studies under in-situ conditions that demonstrate how an external stress field translates to microscopic strain at the pore scale and couples to the fluid transport. These studies rely on the coordinated use of low-field nuclear magnetic resonance (NMR) and X-ray microtomography (XMT). Making use of labeled fluids to enhance contrast, we are able to directly resolve how local strains affect fluid transport throughout the core plug. In a similar manner, proton NMR resolves how stress couples to deformation of the various pore systems, affecting the fluid content and their dynamics. Together, these techniques indicate that internal, high-permeability zones play an important role in the stress dependence. Matrix permeability is much less affected. These higher-permeability zones are not ubiquitous in tight-oil rocks. Characterizing these zones and relating them to mineralogy and rock fabric is an attractive pathway to greater predictability for stress-dependent permeability for reservoir rock types.