The Use of Shear-Thinning Fluids as “Smart” Tracers to Infer Fracture Network Properties

Monday, 14 December 2015
Poster Hall (Moscone South)
Clément Roques1, John S Selker1, Tanguy Le Borgne2, Yves Meheust3, Majdi Abou Najm4, Willie E. Rochefort5, Philippe Davy2, Olivier Bour6, Marion Loiseau5, Sophie Givens5 and Billi Jean Herring5, (1)Oregon State University, Biological and Ecological Engineering, Corvallis, OR, United States, (2)Geosciences Rennes, Rennes Cedex, France, (3)University of Rennes, Geosciences, UMR CNRS 6118, Rennes Cedex, France, (4)American University of Beirut, Beirut, Lebanon, (5)Oregon State University, Chemical, Biological & Environmental Engineering, Corvallis, OR, United States, (6)University of Rennes, Rennes Cedex, France
The identification of preferential flow paths, their connectivity and their hydraulic properties in fractured rocks is critical for fluid flow and solute transport. Classical hydraulic tests allow defining a mean effective aperture based on simplified fracture models. Here we study the potential of using shear-thinning fluids as “smart” tracers to infer the distribution of fracture hydraulic properties. The main hypothesis considers that the flow of a shear-thinning fluid will sample specific pathways of the network as the fluid presents more viscous-shear behaviors. The flow field distribution of shear-thinning fluids in a 2D parallel fracture is first investigated numerically by implementing a viscous-shear model on classical flow equations. The relationship between fracture aperture and the degree of the flow enhancement due to the thinning behavior is quantified - given by the ratio between the non-Newtonian fluid average velocity and its corresponding Newtonian fluid at viscosity. A dimensionless solution describing the flow enhancement with respect to fracture aperture is derived from the theory. We also examine the impact of multiple fracture setups on the flow field redistribution in radial flow condition. Two main fracture configurations that can be found in a real network are considered: fractures organized in series and in parallel. We describe different flow enhancement behaviors controlled by the power exponent of the fluid and the fracture geometry. In perspective, some first experimental results are introduced that will guide the development of an inverse modelling framework.