Estimating spatial distribution of natural fractures by changing NMR T2 relaxation with magnetic nanoparticles

The dynamic distribution of nanoparticles concentration and VMS are graphically displayed along each time step in 3D mesh. The results show that magnetic nanoparticles bring much larger VMS while most nanoparticles only flow into these natural fractures (NF) directly connected with wellbore. The others' NF have somewhat higher VMS than matrix. Additionally, based on various sensitivity cases, a higher concentration of nanoparticles yields a stronger magnetic field, and larger nanoparticle size could lead to higher VMS, although the nanoparticles face stronger flow resistance and less diffusion movement. The CPMG decay curve is a multi-dimensional exponential function related to relaxation amplitudes and times, and the least squares minimization technique can be applied to obtain the T2 amplitudes from CPMG curve. The comparison between two synthetic cases shows the amplitude for small T2 time increases and the amplitude for large T2 time reduces, which provides a clear indicator to detect the locations of natural fractures because their T2 largely reduce. The nanoparticle model provides valuable guidance about choosing parameters for optimizing magnetic nanoparticle injection design to enhance VMS and NMR signals. The inversion model introduces an efficient path for estimating T2 distribution and petrophysical properties from the acquired NMR CPMG signals. Additionally, magnetic Nanoparticles provide excellent relaxation contrasts to distinguish the magnetization signals of formation for estimating the spatial natural fractures distribution. Consequently, in-situ fracture characterization and the development of hydraulic fracture treatments could be beneficially improved.