The porosity model was used to calculate reservoir porosity, using the density log. Reservoir shale cutoff of 55% by using cross-plot between shale volume and porosity (Toby Darling concept) was utilized to discriminate the reservoir from non-reservoir sections.
The average hydrocarbon saturation values range between 46 and 97%. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation subsequently, a new unconventional petrophysical evaluation approach was performed. Hence, a new further investigation and review for the previously calculated GIIP (gas initially in place) was initiated. It is subdivided into three sub-units Kharita A, Kharita B and Kharita C that are in pressure communication. It consists mainly of sandstone with shale intercalations. Upper Kharita Formation produces gas and condensate from the clastic sandstone in Badr-3 field, western desert of Egypt. These inferences are based on petrophysical models utilizing correlations among tools’ responses as well as rocks and fluids properties. The integration of core and logging data responses is often used to draw inferences about lithology, depositional sequences, facies, and fluid content. Accurate determination of pore throats, pores connectivity and fluid distribution are central elements in improved reservoir description. The increase in water-cut ratio reduces the left hydrocarbons’ amount behind pipe. This study aims to evaluate Kharita gas reservoir to enhance the production.