Abstract
High-clay shale formations could behave as a semi-permeable membrane, thus causing osmotic water molecules flow from low-salinity side to the high-salinity side. This chemical potential dominated flow, we believe, has non-negligible influence on water leak-off and flowback during the treatment of hydraulic fracturing, since there is a considerable salinity difference between the low-salinity fracturing-fluid and the high-salinity formation brine.
In this paper, we present the development of a comprehensive triple-porosity (organic materials, inorganic materials and fracture network), dual-permeability, chemical potential dominated water/gas flow model that uses experimentally determined formation properties to predict the fracturing fluid flowback of hydraulically fractured shale gas wells. The dual-permeability includes the chemical potential dominated flow within inorganic materials and the pressure dominated flow within fracture network. Fracture network is considered as an interconnected continuum embedded in shale matrix, where organic shale is interspersed within vast inorganic shale. The organic material is thus considered disconnected in the entire reservoir. The chemical potential dominated flow model accounts chemical osmosis, capillary and viscous forces.
The water saturation profiles for both osmosis-induced and capillary-induced cases are compared, revealing a region of saturation that effectively is immobile even though irreducible saturation has not been reached. The results indicate that chemical osmosis is a key mechanism for fluid loss during the hydraulic fracturing and should not be ignored under high clay content cases. This work provides a basis for flowback data analysis of hydraulically fractured shale gas wells and also helps define value adding laboratory measurements.
