## 3 Results and Discussion
### Effect of Wettability on T\({}_{2}\) Distribution and T\({}_{2}\)LM  
The ability of crude oils to alter the wettability of a pore surface varies. The T\({}_{2}\) relaxation times for fluids existing in rock pores are affected by independent relaxation mechanisms like bulk fluid processes, surface relaxation, and diffusion in the magnetic field gradient. Their relative importance is dependent on the fluids in the pores, pore sizes, surface relaxation strength, and the wetting fluid. The wetting fluid is dominated by surface relaxation. The non-wetting fluid has bulk relaxation as its primary contributing source, while gas is mainly dominated by diffusion in the presence of magnetic field gradients. From NMR data analysis, each fluid exhibits a bulk relaxivity, but when oil molecules wet pore surfaces, they exhibit additional surface relaxivity, thus complicating the T\({}_{2}\) relaxation mechanism. This complication is because the effect of the surface relaxivity spectra on oil is quite different from water. Consequently, when a reservoir exhibits mixed wettability, the situation becomes much more complicated. Based on this notion, this methodology seeks to establish a simplified way of determining reservoir wettability using the relationship between the geometrical mean of T\({}_{2}\) relaxation spectra and water saturation. The results of this relationship are  
Figure 6: Application of Amott-USBM—NMR T\({}_{2}\)LM cross plot to establish an exponential relationship between core and log wettability data. \begin{table}
\begin{tabular}{c c c c c c} \hline \hline
**Sample ID** & **Depth m** & \begin{tabular}{c} **Amott** \\ **Wettability** \\ \end{tabular} & \begin{tabular}{c} **USBM Wettability** \\ **Number** \\ \end{tabular} & \
\begin{tabular}{c} **Wettability** \\ **Indicated** \\ \end{tabular} &
\begin{tabular}{c} **Modified Wettability Indicated Using** \\ **the Wettability Scale in This Study** \\ \end{tabular} \\ \hline
8 & 1271.60 & 0.313 & 0.479 & Water wet & Water wet \\
9 & 1271.90 & 0.158 & 0.443 & Water wet & Moderately water wet \\
10 & 1272.21 & 0.143 & 0.750 & Water wet & Moderately water wet \\
15 & 1273.70 & 0.116 & 0.719 & Water wet & Moderately water wet \\
62 & 1290.75 & 0.513 & 0.582 & Water wet & Strongly water wet \\ \hline \hline \end{tabular}
\end{table} 
Table 5: Initial wettability states and modified wettability states for core samples. then related to an Amott-USBM wettability measurement from core data through a new empirical equation. Figures 7 and 8 show a schematic representation of wettability's effect on the T\({}_{2}\)LM log based on water saturation distribution. Analysis shows that a variation in water saturation distribution within the pore spaces affects the NMR relaxation times. The wettability effect of the surface relaxivity phenomenon occurs for a water-wet system where under increasing oil saturation, there is an observed but slight decrease in T\({}_{2}\)LM. When water is wetting the pore surface, the water experiences additional surface relaxation. However, the non-wetting fluid, which is oil, will only experience bulk relaxivity. Therefore, there is an increase in the water phase T\({}_{2}\) relaxation time at decreasing water saturation. The bulk relaxation time for water is between 10 and 100 ms. In contrast, the peak relaxation of oil is around 1000 ms, although this is mainly for oil with high gas-oil-ratio. At 100% water saturation, T\({}_{2}\) is usually around 10 ms [57]. When oil is encountered in the interval, T\({}_{2}\) tends to peak, signifying the additional oil relaxivity. The  
Figure 8: Schematic illustration of NMR T\({}_{2}\)LM distribution as a function of water saturation in an oil-wet condition. Figure 7: Schematic illustration of NMR T\({}_{2}\)LM distribution as a function of water saturation in a water-wet condition. contribution of bulk oil relaxation time will be subtle, whereas the water phase dominates. This behaviour causes the T\({}_{2}\) relaxation time to shift to a slower phase.