## 5 Discussion  
The application of resistivity and sonic logs, and [PERSON]'s method of generating a depth-dependent NCT produced relatively similar pore pressure results for all three reservoirs (Figures 3 and 6). The three studied reservoirs' estimated mud weights (MW) were 2.00 gm/cc, 0.26 gm/cc, and 0.79 gm/cc, respectively. These mud weights are needed to maintain the borehole's stability during drilling [5; 8]. Precisely estimating the mud weight would minimize mud loss or circulation during drilling. However, if excessive mud weight is employed, the will experience fluid circulation loss, meaning that the hydrostatic pressure of mud with an abnormally low mud weight will be less than the pressure of the formation [8; 11; 62; 63]. As a result, pressure fluid from the formation will start to rise to the surface through the wellbore and cause a kick in the formation, resulting in an uncontrollably high blowout should the invasive fluid reach the surface [5; 8; 11; 63; 64]. Figure 13: Well E-CB1 comparison of log and pressure data (RFT). Therefore, to avoid formation fracture as measured by PPG_Res and PPG_Sonic, the MW must be lower than the fracture gradient values to avert circulation loss and kicks during the formation drilling process. This ensures that the wellbore remains stable and that the fracture gradients will be maintained before cementing and installing the well's casing, preventing the borehole's fracture during drilling. The effective stresses (ES) within the studied reservoirs were recorded as \(-\)7.98 gm/cc, \(-\)8.02 gm/cc, and \(-\)10.17 gm/cc, respectively. These values suggest that overpressured formations would be encountered when drilling across the studied interval due to the negative impact of the effective stress. ES enhances the detection of overpressured and normal pressured formations [11; 57]. The predicted pore pressures (PPP) likely to be encountered during the drilling of the selected wells were 4258.03 psi (PP_Res) and 4196.80 psi (PP Sonic) in well E-BK1, 4310.06 psi (PP_Res) and 3818.78 psi (PP_Sonic) in well E-AJ1, and 3563.74 psi (PP_Res) and 3578.75 psi (PP_Sonic) in well E-CB1, respectively (Table 3). Notably, normal pore pressures and overpressure zones were identified in all the wells except for E-AJ1. Significant overpressure zones were identified from 2685 m to 2716 m, and from 2716 m to 2735 m in the pores exceeding 7996.43 psi (Figure 6). The Eaton's resistivity and density/neutron methods confirmed the normal pressure zones in E-BK1 (Figure 3) and overpressured zones in E-AJ1. However, in E-CB1, the resistivity and density/neutron log methods detected an overpressured zone enhanced by the undercompaction of the formation. These pore pressures were observed from sonic shale and resistivity shale log deviations from the NCT. Overpressured formations were detected by shale resistivity when the log deviated from the NCT towards the lower values, whereas the sonic shale log detected the overpressured formations when it deviated from the designated NCT towards the higher values. Conversely, when shale resistivity deviates from the NCT towards the higher values, it suggests a normal pressure formation, and the deviation towards the lower values suggests a normal pressure zone for sonic shale logs [10; 55]. The pore pressure results (Table 2) showed that the Eaton resistivity, Mathews and Kelly, Modified Eaton, and Baker and Wood, and Bowers methods agree with each other, whereas the Eaton sonic method showed varied results. This discrepancy occurs because, when determining the Normal Compaction Trend (NCT) of the formation, which depicts the expected compaction behavior of the formation with increasing depth, the Eaton sonic method detects the abnormal pressure formations by identifying sonic shale log (DT) deviations from the established NCT towards the higher values. Other methods detect abnormal pressure (overpressure) formations by identifying the resistivity of shale deviations from the NCT established closer to the lower values [10].