Quantifying the Impact of Petrophysical Properties on Spatial Distribution of Contrasting Nanoparticle Agents

Abstract

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 reliable and real-time in situ petrophysical characterization at all the desired depth intervals. While several studies focus on improvements in workflows for core measurements and well-log interpretation methods, we approach this challenge by introducing techniques to enhance the sensitivity of well logs to petrophysical properties of the formation and to the presence of natural fractures. Similar in approach to the application of nanoparticles as contrast agents to improve medical imaging, this paper introduces the use of nanoparticles as contrast agents that can travel into the rock and influence well logs based on their properties.

This paper quantifies 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 homogenous and heterogeneous rocks. We also synthesized nanoparticles and characterized their morphology and magnetic properties. These particles contain an iron oxide core and a carbon shell, which increase the stability of nanoparticles. The effluent history of nanoparticles injected into rocks in coreflood experiments was used to validate the performance of the developed numerical simulator.

We documented the results of numerical simulations for homogenous and heterogeneous naturally-fractured porous media. The rate of transport of the nanoparticles increases as the permeability increases as a result of the effects of advection and dispersion. However, radial length of nanoparticle invasion decreases as the porosity increases. The presence of natural fractures increases the transport of nanoparticles as a result of higher permeability in fractures. The sensitivity analysis shows negligible impact of nanoparticle size on the spatial distribution of nanoparticles in the case of 1-nm-diameter, 10-nm-diameter, and 100-nm-diameter nanoparticles because of the dominance of dispersion over diffusion effects. The effluent history from the coreflood of sandstone with the synthesized nanoparticle solution closely predicts the results from numerical simulations. In this paper, we use a numerical simulation approach to identify the factors affecting transport of nanoparticles in the near wellbore region, which in turn affect borehole geophysical measurements. The enhancement of the sensitivity of well logs to formation properties can improve evaluation of petrophysical properties and the characterization of natural fractures.