From NMR Signals to Fracture Size: Capillary-Controlled Conversion for Shale

Fracture size governs fluid mobility in shale, yet its direct quantification remains challenging. Nuclear Magnetic Resonance (NMR) transverse relaxation time (T2) offers a unique, non-destructive probe of fracture size distributions; however, a physically grounded conversion from transverse relaxation time to pore radius r (T2−r) is essential to translate NMR signals into quantitative geometric constraints on fluid mobility. This study introduces a capillary-constrained experimental method for T2−r transformation into shale fractures. The workflow uses computed tomography (CT) scanning to extract fracture geometry. The gas-displacing-water process is precisely controlled by integrating the pore capillary pressure and back-pressure feedback algorithm. The NMR-CT conversion method performed in this study differs significantly from the T2−r transformation based on conventional MICP. Differential spectral analysis isolates fracture-specific T2 responses, and least-squares fitting derives the T2−r conversion. Constraining displacement pressure and controlling segmental pressure are effective methods for ensuring the accuracy of fracture displacement. By emphasizing the governing role of capillary pressure during displacement, this method achieves accurate fracture-targeted displacement and reliable T2−r mapping. The results significantly advance the use of NMR for quantifying fracture size and evaluating fluid transport in shale.