## 2 Materials and Methods
### Petroleum Potential Evaluation
#### 2.2.2 Source-Rock Characterization  
To assess the spatial and temporal variations in source-rock quality, Rock-Eval pyrolysis was performed on samples from two exploration wells, NGJ and KTB, using a Rock Eval 7 analyzer. These results, combined with geochemical data from the TRC well reports, facilitated an understanding of the source-rock characteristics and formed the basis for source-rock geochemical and kinetics inputs for the subsequent BPSM modeling stage. The TRC well samples exhibited an average total organic carbon (TOC) of 3.5% and a hydrogen index (HI) of 367 mg/g TOC, indicative of favorable petroleum source-rock conditions. These parameters were integrated into the BPSM for model input and calibration. Geochemical data, including TOC, HI, vitrinite reflectance (VR), and kerogen types from organic-rich shale facies of the Mid-Moocene intervals, were utilized to assess hydrocarbon potential. Basin and Petroleum Systems Modeling is a powerful tool used for evaluating temperature, source-rock maturity, and generation and migration of petroleum in sedimentary basins [28; 29; 30]. The 1D BPSM methodology is a fundamental approach in petroleum geology that models the geological and geochemical evolution of sedimentary basins along a single vertical profile. It helps researchers understand the timing of sediment deposition, compaction, and hydrocarbon generation by simulating the thermal and burial history over geological time. This methodology is essential for predicting the maturation levels of organic-rich source rocks and provides insights into hydrocarbon generation, expulsion, and migration [31; 32; 33]. By integrating various datasets, including stratigraphic, geochemical, and boundary data, 1D BPSM can enhance the accuracy and reliability of predictions, thereby reducing exploration risk. It is the most applicable tool where data is scarce, compared to more complex multi-dimensional models, serving as a preliminary guide and fundamental step towards more detailed and sophisticated 2D or 3D modeling efforts. Additionally, it allows for testing different geological scenarios and hypotheses, making it crucial for exploring and assessing hydrocarbon resources effectively. This method is performed using various software packages tailored for BPSM, including PetroMod (Schlumberger), Genesis-Trinity (Zetaware), and Permedia (Halliburton), among others. PetroMod is the most widely used in the petroleum industry due to its versatility [34]. PetroMod 1D can function independently or as an integrated part of the PetroMod 2D and 3D modeling systems. Single-point data, including wells and pseudo-wells, can be created from scratch, imported from the Well Editor, or extracted from PetroMod 2D and 3D models. In this study, Schlumberger PetroMod 1D was utilized to model an exploration well TRC and a pseudo-well X strategically located approximately 12 km apart. The stratigraphic dataset used for this modeling is detailed in Tables 1 and 2. After defining the stratigraphic dataset to be used in the model, the next step was to define the boundary conditions to be applied. Boundary conditions in PetroMod BPSM are critical for simulating thermal and pressure regimes in the basin over time. Parameters such as surface temperature, basal heat flow, paleo-water depth, and sediment-water interface temperature are assigned based on regional geological and geophysical studies. These values, often sourced from the literature or from measured data, are calibrated to match borehole temperature and vitrinite reflectance (Ro) trends. Proper boundary condition assignment ensures accurate modeling of heat transfer, maturation processes, and hydrocarbon generation. Boundary conditions, including surface temperatures and heat flow through time, were applied based on published heat flow data [35; 36] and PetroMod-1D sea level curves, incorporating surface water interface temperatures specific to the locality (e.g., 24-25 \({}^{\circ}\)C for the Albert Rift).