Estimating nuclear magnetic resonance transverse surface relaxivity in pre-salt carbonates of the Santos Basin, Brazil

Abstract

This study explores the Nuclear Magnetic Resonance (NMR) characteristics of pre-salt carbonates rocks, focusing on transverse relaxation time (T₂) cut off values and surface relaxivity parameters. We analyzed nine carbonate samples to capture the petrophysical heterogeneity of the Barra Velha and Itapema Formations in the Santos Basin, Brazil. By relating NMR T₂ with the surface-area-to-volume (S/V) ratio, surface relaxivity was determined using Mercury Injection Capillary Pressure (MICP) and X-ray microcomputed tomography (μCT) to enhance pore size estimation. Based on NMR results, samples were grouped into three categories: Group 1 (Samples A, B2, B3, C, D2, D3, E): T₂ peaks above the cut off, dominated by macropores; Group 2 (Sample B1): Bimodal T₂ distribution, indicating a mix of macro- and micropores; Group 3 (Sample D1): T₂ peaks below the cut off, suggestive of micropore dominance and irreducible fluid storage. The study observes that while these patterns are not sufficient for distinguishing facies types, a comparative analysis of MICP pore-throat sizes and NMR T₂ distributions reveals essential insights into pore system variability. Notably, larger dissolution-related pores in Samples A (coquina) and D2 (spherulitic shrubstone) affect permeability estimation. The maximum T₂ cut off for spherulitic shrubstones was 0.65 s, highlighting the significance of pore structure in fluid storage and transport. Additionally, results underscore the vital role of surface relaxivity in converting T₂ to pore size, showing that relaxivity is more influenced by rock morphology and texture processes than solely by iron composition such as presence of coatings or presence of vuggy or cavities. Incorporating relaxivity into NMR models significantly improved permeability estimation accuracy, with the ρ-corrected model (R² = 0.84) outperforming traditional SDR and TIM models. These findings emphasize the necessity of integrating NMR, MICP, and μCT techniques for a comprehensive understanding of pore architecture and fluid flow in heterogeneous carbonate reservoirs.