Petrophysical evaluation of complex formations using well logs is challenging due to the uncertainty in conventional petrophysical models in these reservoirs. Core measurements, on the other hand, are usually sparse and do not provide real-time and in-situ depth-by-depth petrophysical characterization. Several studies focus on improvements in workflows for core measurements and well-log interpretation methods. However, we approach this challenge by introducing a method to enhance the sensitivity of well logs to petrophysical properties of the formation and to the presence of natural fractures using nanoparticles as contrast agents that can travel into the rock.

We quantify the effect of petrophysical properties of porous media on the spatial distribution of magnetic nanoparticles injected as contrasting agents to the formation. We achieved this goal by developing a two-phase fluid-flow numerical simulator for transport of injected nanoparticles in fractured porous media and synthesizing magnetic nanoparticles and characterizing their properties. The developed simulator takes into account the deposition/adsorption of nanoparticles based on colloid filtration theory and Brownian diffusion. We documented the results of numerical simulations for homogenous and heterogeneous naturally fractured porous media. The effluent history from the coreflood of sandstone with the synthesized nanoparticle solution confirms the results from numerical simulations. We showed that the nanoparticles are mostly concentrated in the connected natural fractures when the permeability of matrix is significantly lower than that of fractures. The sensitivity analysis shows negligible impact of nanoparticle size on spatial distribution of nanoparticles because of the dominance of dispersion over diffusion effects. The results are promising for measureable impact of nanoparticles on specific borehole geophysical measurements to better characterize naturally fractured rocks.

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