## 5 Discussion
The wireline logs and RFT data identified fluid contacts within the selected reservoir intervals. The RFT results identified fluid contacts only in two wells, E-AJ1 and E-CB1. The fluid contacts in E-BK1 (Figure 9) could not be determined because of the missing RFT data. In E-AJ1 (Figure 10), oil-water and gas-oil contacts (GOC and OWC) were encountered at 2699 m and 2723 m, with a water density of 1.01 g/cm\({}^{3}\), gas density of 0.23 g/cm\({}^{3}\) and an oil gradient of 0.69 g/cm\({}^{3}\). In E-CB1 (Figure 11), an oil-water contact (OWC) was encountered at a depth of 2528.5 m, with a water density of 0.97 g/cm\({}^{3}\) and an oil density of 0.62 g/cm\({}^{3}\). The following observations were made from the wireline logs (resistivity, density and neutron): A gas-water contact (GOC) was encountered at 2967.5 m in E-BK1. Gas-oil and oil-water contacts (GOC and OWC) were encountered at 2699 m and 2723 m depths in E-AJ1 (Figure 12), and an oil-gas contact (OGC) was encountered at 2523 m in E-CB1 (Figure 13). Fluid contacts observed from the well logs and RFT pressure data (Table 4) in E-AJ1 were in close agreement as they showed similar depths of encounter. There was no agreement between the well log and RFT fluid contact in E-CB1 (Figure 13), with a discrepancy of 5.5 m. These discrepancies could be attributedto the inaccuracy of the fluid densities estimated from pressure gradients. The estimated fluid densities in the E-CB1 well differ from the actual densities. (The actual density for gas is 0.08 g/cm\({}^{3}\), that for water is 1 g/cm\({}^{3}\), and that for oil ranges between 0.7 and 0. 9 g/cm\({}^{3}\).) The estimated fluid densities for oil (0.62 g/cm\({}^{3}\)) and water (0.97 g/cm\({}^{3}\)) were lower than the actual densities. Considering the inaccuracies regarding the fluid densities in E-CB1 estimated from the pressure gradients, the OGC contact from RFT data could be assumed to be inaccurate. This observation agrees with those of [8]. The possible explanation for the differences between the estimated and actual fluid densities in E-CB1 may be due to formation testers not recording pressures from the virgin fluid but from a mixture of water and hydrocarbons [8]. This is usually the case in thicker and high-quality reservoirs [8]. Ref. [19] also observed discrepancies between the RFT and well log contacts in the nearby basin and attributed the discrepancies to the presence of chlorite minerals in the reservoir, leading to the inaccurate reading of the resistivity log in the formation. As previously highlighted by [65], the reservoirs in this basin contain a substantial amount of chlorite. Other factors could be pressure variations, high water production, and supercharging in this well. Changes in pressure affect the fluid contact depth, leading to differences between the well log and RFT data. An increased pressure can cause the fluid contact to move downward, resulting in a deeper FFT-measured depth. High water production in the well, likely due to the dominant clay mineral, leads to low resistivity readings. This can cause the well log data to indicate a shallower fluid contact depth compared to the RFT data. Supercharged pressure points were observed in well E-CB1. Supercharged points often occur in very low permeability environments when the formation is overpressurized [19]. In contrast, the estimated fluid densities from the pressure gradients in E-AJ1 were similar to the actual densities (Table 3); hence, RFT and well logs identified similar fluid contacts. Putting it all together, we observed that the results (Figures 10-13) showed a close correlation between fluid contact and pore pressure. Fluid contacts associated with overpressures were gas-water and oil-water contacts. In contrast, gas-oil contact was associated with underpressure. Generally, drive mechanisms play an important role in influencing the nature of the fluid contacts and the associated formation pressures. A gas cap drive mechanism influences the low pressure encountered in the GOC.