The Gharif formation of Southern Oman is formed by an alternation of channel belt sands, paleosols, subaqueous shales and marine sediments. In the fluvial heterolithic sequences the traditional petrophysical model failed to identify the thinner oil bearing sandstones. This is due to low net-to-gross (NTG) with sands below the resolution of traditional logging tools and low resistivity pay sands due the presence of shale-laminations.
An interpretation strategy for hydrocarbon identification has been developed using the Thomas-Stieber approach. The main outputs of this model are NTG (laminated shale:sand) and true sand porosity. Knowing the volume of laminated shale, the true resistivity can be modeled using the laminated resistivity model. However the Thomas-Stieber requires a large number of parameters whose selection can be difficult and prone to large errors. In addition the model assumes a single uniform porosity for clean sands which may not be true for the Gharif formation.
A more direct method for hydrocarbon detection and reservoir quality determination can be obtained using NMR logs. The NTG and total porosity can be directly determined from the T2 distribution. NTG determined in this way is comparable to NTG derived from the Thomas-Stieber model, and used in the laminated resistivity model. The presence of hydrocarbon can be confirmed by generating T2-diffusion maps. These maps assist in identifying hydrocarbon even in the most heterogeneous intervals. Using NMR data bound water and permeability can be calculated from the T2 distribution. Using this data it is possible to determine whether or not the interval of interest will produce oil, the amount of mobile water and an approximation of the water-cut.