Abstarct: In the realm of modern oil well operations, Sand Production (SP) is a major challenge, requiring the prompt identification of its root causes and the formulation of effective mitigation strategies. As such, the precise determination of these factors, their respective threshold limits, and the optimization of oil production rates are paramount. These elements exert a profound influence on critical technical dimensions—particularly in terms of economic impact, safety considerations, and the timeline for attaining peak production efficiency. The Cased, Cemented, and Perforated (CCP) well completions stand out as one of the most optimal well completion methods for such weak reservoirs, offering superior safety and cost-efficiency compared to alternative approaches, and significant potential for increasing hydrocarbon production over OpenHole (OH) completion methods. This study investigates SP, focusing on its underlying causes, production capacity, and the development of appropriate geomechanical strategies to mitigate SP in well 469, drilled within the Asmari formation of the Ahvaz field. The preliminary evaluation was performed using Techlog software, and the required parameters for constructing a one-dimensional geomechanical model were derived from available data. The Mohr-Coulomb failure criterion, incorporating scale effects for perforated cavities under non-hydrostatic stress conditions, was applied in the analysis. Following the development of the one-dimensional model, the Critical DrawDown Pressure (CDDP) curve was generated for both OH and CPP well conditions, delineating regions prone to SP. The M2 laxyer, characterized by its relative weakness, exceptionally high porosity, and permeability several times greater than that of other laxyers, was identified as one of the most vulnerable zones for SP. This laxyer was chosen for sensitivity analysis of the key parameters. The analysis was conducted baxsed on well geometry, the predominant grain diameter of the sand, stress field conditions, and the specific characteristics of the perforated cavity. Sensitivity analysis was performed on sand with a dominant grain diameter of 200 microns within the identified region prone to SP. Building on this analysis, a novel approach for designing perforation operations in reservoirs affected by SP is introduced—an approach that precisely defines and determines the Transitional Deviation Angle (TDA), Minimum Safe Deviation Angle (MSDA), and Critical Perforation Orientation Angle (CPOA). Consequently, the most suitable well trajectory and perforation configuration, along with the range of safe perforation angles for both deviated and horizontal wells, are identified. Given that the number of Shots Per linear Foot (SPF, spf) in perforation design is typically determined baxsed on the required hydrocarbon production volume, optimizing the phase angle (phasing) becomes a critical design parameter. This optimization aims to prevent the overlap of damaged zones surrounding adjacent perforations and to minimize their interaction, thus ensuring the efficiency of the perforation pattern. Considering the absence of constraints and the simplicity of generating a Single Helical Perforation Pattern (SHPP) compared to other perforation configurations, this study focuses on identifying the optimal phasing by examining the minimum distance between adjacent perforations, termed the minimum Perforation-to-Perforation Spacing (PPSm), resulting from various phase angle configurations within this pattern. The uniform distribution of perforations is achieved using mathematical and statistical concepts through the definition of a parameter known as the Equilateral Likeness Score (ELS). The minimum value of this parameter indicates the most uniform distribution of adjacent perforations. The optimal phase angles have been discerned from two distinct vantage points—maximizing the spacing between adjacent perforations and maximizing the feasible angle values for the phasing. A comparative analysis between the outcomes derived from the proposed theory and those from prior theories—including the Isosceles Obtuse Triangle Pattern (IOTP)—reveals the likelihood of notable disparities in the calculated optimal phase angles. In loosely consolidated sandstone hydrocarbon reservoirs, Expandable Sand Screens (ESS) play a pivotal role due to their ability to mitigate cavity instability and enhance the effectiveness of perforation operations—often resulting in a significant reduction in SP, sometimes to negligible levels. This study examines the impact of installing ESS in the reservoir under investigation through two-way coupled solid-fluid numerical modeling—using one of the most robust discrete element software platforms, the Particle Flow Code (PFC). The static model of the reservoir was constructed with grain sizes corresponding to the Particle Size Distribution (PSD) of the Asmari formation—maintaining its porosity. Following the distribution of spheres within the model, their radii were adjusted to minimize overlap with neighboring spheres while preserving the number of contacts to the minimal depth of overlap for each sphere. Consequently, the PSD remained close to the original distribution. By connecting the free spheres to the main body of the model, a unified model was created. Upon applying the stress load to the model, the skin effect caused by SP during extraction was evaluated using both steady-state and transient solvers. The simulation results indicate that SP from the OH completed well remains within acceptable limits, and the application of ESS reduces SP to zero—effectively preventing SP even at high hydrocarbon production rates of up to 10 thousand barrels per day. The negative skin factor observed for sand production in the OH condition indicates that optimizing other skin factors can enhance this well's productivity.