Non-linear poromechanics and fluid flow in tight rock - Texas A&M University (TAMU) Scholar

Proper characterization of the mechanical and flow properties of participating rock formations is crucial for subsurface geo-energy projects, including hydrocarbon extraction, geologic carbon storage, and enhanced geothermal systems. Application of mechanical and hydraulic pressures changes the porosity of rock and modifies flow paths. For low-permeable or "tight" rock that mainly contains nanoscale pores and serves as the confining layer for underground storage operations, a significant change in permeability may occur due to a small change in porosity. The pore volume changes in nanoporous geomaterials are extremely difficult to measure directly but can be assessed from the knowledge of the mechanical response. Experimental methods to measure the stress-dependent permeability and poromechanical parameters of fluid-saturated tight rock are introduced. Eau Claire shale and Opalinus clay (claystone) are chosen as the representatives of clayey caprock, while Precambrian rhyolite and Charcoal granite are selected as the bedrocks. The porosity-permeability relationship for tight rock is established by adopting a power-law dependence with the exponent value in the range of 15-17, thus being significantly larger than that for a porous reservoir rock. Consequently, even small perturbations of porosity can cause orders of magnitude changes in permeability, possessing a risk on the sealing capacity of the tight formations.

Non-linear poromechanics and fluid flow in tight rock Conference Paper