Abstract

Capillary pressure (Pc) governs hydrocarbon distribution in reservoirs, making it a critical component of reservoir characterization. Traditionally, Pc curves are derived from Mercury Injection Capillary Pressure (MICP) measurements obtained through Special Core Analysis (SCAL). However, in unconventional reservoirs, target being a heterogeneous section, core data often becomes insufficient. Hence, with limited SCAL data which are point data, alternative methods are required to derive a continuous fine resolution data. This study presents an approach to derive Pc curves using Nuclear Magnetic Resonance (NMR) T2 relaxation time in an unconventional formation of a UAE field. For the target unconventional formation, a scaling factor has been derived, and a hydrocarbon correction is applied, and a proportionality constant (k) is introduced to calibrate the T2–Pc relationship, aligning T2 spectra with capillary behaviour. An algorithm using T2 cutoff ensures that sum of bound and movable fluid volumes match the water-filled porosity, compensating for hydrocarbon effects. The methodology has been tested on the UAE unconventional formation having carbonatemudstone lithology. The derived Pc–Sw curves from NMR data were compared with MICP curves, showing strong correlation with consistent entry pressures and irreducible water saturation (Swirr) trends across various rock types. These results enabled continuous, depth-wise Pc–Sw relationships, overcoming the spatial limitations of core-based MICP. The outputs, combined with porosity and permeability, were used in Self-Organizing Map (SOM) clustering to identify the best rock quality zones. Integration with completion quality parameters led to successful hydrocarbon discoveries, validating the adopted methodology and study