## 1 Introduction  
Porous media are composed of solid mineral grains and empty spaces, or pores. An important parameter of this pore structure is the spaces between these grains and their shape. The spaces in porous media serve a dual purpose, serving as channels for fluid transportation, forming interconnected pores, and as reservoirs for fluid storage. During geologic time, when sediments were deposited and rocks were formed, some void areas became isolated due to excessive cementation. As a result, many void spaces are interconnected, while others remain isolated [1]. There are several types of porous media, one of which is rock. Rocks are porous media because there are empty spaces in them. The spaces in the rock can be empty spaces or filled by fluid. In most rocks, reservoir rocks generally have a higher pore volume so that the empty spaces in reservoir rocks are generally the places where hydrocarbons accumulate [2]. The porosity of the rock is the ratio of the volume of pore cavities to the overall volume, and can be classified as the absolute or effective porosity. Effective porosity is when the pores are interconnected, allowing fluid flow, while absolute porosity is calculated without connections between the pores. Therefore, effective porosity is the most important parameter influencing permeability [3; 4]. Porosity measurement in reservoirs is important in evaluating and making decisions in petroleum field development. Physical rock parameters are measured in the laboratory but this is time-consuming and can destroy rock samples. Another method to determine rock parameters is by estimation based on matching parameters from rock lithology, grain size, and others, but this method is limited to rocks from specific locations [5]. Permeability is an essential petrophysical parameter to determine the flow characteristics of hydrocarbons [6] and can be calculated by fluid flow simulation, nuclear magnetic resonance, core analysis, and digital rock physics [7; 8; 9]. However, laboratory measurements are difficult to perform for fluid flows that are not gas because some clays attach to the porous media, causing the fluid to be contaminated and mixed [10]. Computational Fluid Dynamics (CFD) serves as an alternative method for determining effective parameter values in rocks through fluid flow simulation. This approach offers advantages such as the elimination of fluid contamination and reduced measurement time [8]. In this study, the fluid flow simulation is conducted using the Lattice Boltzmann method (LBM) for single-phase flow [11]. The LBM is a numerical technique that employs a mesoscopic approach to model fluid dynamics, particularly effective in handling complex boundary conditions like those found in porous media. Previous research has utilized the LBM for various applications, including investigating the flow of non-Newtonian fluids in fracture networks [12], simulating gas flow, and predicting permeability in porous media by comparing single relaxation time (SRT) and multiple relaxation time (MRT) schemes [13], and modeling heat transfer processes [14; 15]. These studies have demonstrated the validity of the LBM in simulating fluid flow in complex geometries. The present study focuses on simulating single-phase flow in 2-D porous rock media using the LBM to obtain velocity and pressure profiles, which are then used to calculate effective fluid parameters. The permeability of the rock was determined through [PERSON]'s law, comparing fluid flow simulation results with digital image analysis [8]. The rock sample used in this study was sandstone, which had undergone prior pre-processing [16]. The physical parameters were calculated using the OpenLB software to simulate fluid flow [17]. In this paper, we employed a 2-D model to investigate the interrelations among effective porosity, permeability, average throat size, and tortuosity due to its ability to effectively capture essential behaviors and trends while being computationally efficient.