Reservoir rocks are not mostly clay-free. The type of clay mineral and its distribution affect the properties of the reservoir rock. Clays can change porosity, permeability and effect logging tools response. Shale can effect on reservoir quality, if the effect of shale on porosity and permeability is ignored that can effect on reservoir final estimation. Porosity, which is one of the important characteristics of reservoir is measured using sonic, neutron and density log. These logs are strongly affected by shale. The shale in the formation due to the presence of clay mineral with the content of water, affects the hydrogen response of these logs from the formation. Therefore, the porosity calculated from the neutron and density log, regardless of the shale volume, have error. As a result, it is necessary to take into account the exact volume of shale in the porosity calculations resulting from logging. In the present study, natural gamma, neutron-density, porosity log (M-N) and Holgs-Lehmann averaging methods and neutron-gamma cross-plot were used to estimate the shale volume. The results of these methods were compared with core analysis studies in different depths. Generally, the conclusion obtained from shale volume estimation using natural gamma, neutron-density, porosity log (M-N), Holges-Lehmann averaging and neutron-gamma cross-plot shows the method of using the corrected gamma ray log (CGR) and the combination of the three porosity log (M-N) give a good estimate of the shale volume. In cases where gamma ray diagrams are not available in the well under study, the M-N method provides a good estimate of shale volume compared to other methods. It seems that the presence of lithological variability at a certain depth affects the estimation of shale volume using any of the methods. In general, corrected gamma ray (CGR) seems to be more efficient in variable lithology.