###### Abstract  
Understanding tortuosity is essential for accurately modeling fluid flow in complex porous media, particularly in the sub-surface reservoir rock; therefore, tortuosity estimation was evaluated using three approaches: Streamline streamline simulations via the Lattice Boltzmann Method (LBM), geometric pathfinding using [PERSON]'s algorithm, and empirical modeling based on pore-structure parameters. The analysis encompassed 1963 micro-Computed Tomography (micro-CT) images of Brazilian pre-salt carbonate and sandstone samples, with the effective porosity extracted from LBM velocity fields, isolating flow-contributing pores, establishing streamline tortuosity as the reference standard. Sandstones exhibited relatively narrow tortuosity ranges (Dijkstra: 1.29-1.75; Streamline: 1.18-2.61; Empirical: 1.18-4.42), whereas carbonates display greater heterogeneity (Dijkstra: 1.00-3.18; Streamline: 1.00-3.68; Empirical: 1.59-4.93). Model performance assessed using the corrected Akaike Information Criterion (AICc) revealed that the best agreement with the data was achieved by the semi-empirical model incorporating coordination number and minimum throat length (AICc = \(-\)113.11), followed by the Dijkstra-based geometrical approach (\(-\)99.74) and the empirical porosity-based model (202.23). There was a nonlinear inverse correlation between tortuosity and effective porosity across lithologies. This comprehensive comparison underscores the importance of incorporating multiple pore-scale parameters for robust tortuosity prediction, improving the understanding of flow behavior in heterogeneous reservoir rocks. D 2025 15 7467 12 June 2025 12 June 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 July 2025 12 June  
to porosity and permeability since more complex flow paths tend to reduce flow space and the medium's capacity to transmit fluids [4; 5; 6]. Rock types such as sandstone and carbonate have significant hydrocarbon potential, with the relatively uniform pore system in sandstone dominated by intergranular pores formed during deposition and early diagenesis [7; 8; 9]. Consequently, sandstone exhibits relatively homogeneous petrophysical properties and a more predictable relationship between porosity, permeability, and tortuosity compared to carbonate rocks. However, diagenetic processes such as cementation, local dissolution, and structural deformation can significantly alter the pore system, affecting connectivity and tortuosity [10; 11]. In contrast, carbonate rocks, especially Brazilian pre-salt carbonate, also possess very high hydrocarbon potential but with more complex structures [12; 13] due to long geological evolution and intensive diagenetic processes [14; 15]. Unlike the relatively uniform pore system of sandstone, pre-salt carbonate formed in a lacustrine (ancient lake) environment beneath salt layers undergoes a series of processes such as dolomitization, selective dissolution, recrystallization, with the overburden pressure of thick salt layers causing thermal and tectonic influences [16; 17; 18]. Consequently, the pore system is highly heterogeneous, consisting of a combination of intergranular pores, moldic pores, vuggy pores, and micro- to macro-fractures. The pores vary in shape and size, as well as connectivity and directional orientation, creating a highly anisotropic medium [19]. The resulting fluid flow paths are not homogeneous or isotropic, thus posing significant challenges in representing and accurately calculating actual flow paths within the rock. Therefore, a multidisciplinary approach is necessary to quantify tortuosity while describing its relationship with other physical parameters such as throat radius, porosity, and permeability [6]. Tortuosity is classified into several types, including geometric, hydraulic, diffusive, and electrical tortuosity [20].