Gas miscibility injection is one of the most effective ways to increase oil extraction. The Minimum miscibility pressure is an important parameter in the miscibility gas injection processes, which is very important for determining the type of injection gas and the design of injection facilities.1 In the industry, the minimum miscibility pressure is usually measured by slim tube, which is a relatively costly and time-consuming test, and may sometimes be counterproductive due to its specific problems, in spite of the high cost and time consuming costs. In this study, using the eclipse 300 simulator, the minimum miscibility pressure was calculated for 11 oil reservoirs with different injectable gases in the process of gas miscibility injection after simulation and compared with the experimental results of these 11 reservoirs and by calculating error percentage, the applicability of this method has been investigated.

Determination of shale type in shale formation has long been a difficult task. Presence of shales in some of the Iranian reservoir formations are one of the most important subject. Shale types have to be considered, because existence of shale type reduces, effective porosity and permeability of the reservoir to some extent. Allogenic Shale is distributed in formations in three basic types, Dispersed, Laminar and structural. Each of these shale types has different effect on porosity, permeability and water saturation. Dispersed shale type reduces effective porosity and permeability to a great extent, but, laminar and structural have less effect on petrophysical parameters. In this investigation, shale types, Shale volume and effective porosity of shale formations have been determined from well logs based on cross-plotting. In other words, a triangle Density-Neutron cross-plot is used to determine the above parameters. The area of study chosen from central oil fields of Iran, where some of the wells are used (Tabnak Field). Tabnak Well C selected for this study in Kangan Formation, South Pars. This study illustrates that distribution of shale types in Kangan Formation is mainly dispersed shale with few of laminar shale, and the quality of effective porosity (φ e ) decreases with increasing depth in the Kangan Formation.

Shale volume can be estimated from the gamma ray log. The following equation is used to determine the Gamma ray indexWhere IGR is the Gamma Ray Index, CGR log is the Gamma Ray response in the zone of interest, CGR min is the Gamma Ray response in cleanest formation, CGR max is the Gamma Ray response in shale zone.A and B are log calibration constants, Log Th is the Log of Thorium and Log K is the log of Potassium.The shale volume (V sh ) can be calculated from the Gamma ray index in shaley formation Corrections of Reservoir Parameters in Shaley FormationCorrections for hydrocarbon effects in shaely formation are For the neutron porosityIn fresh mud's (ppm less than 50000), the parameters are Δ φN = φS hr (ρ h -0.7) for oil (4) Δ φN = φS hr (2.2ρ h -1.0)for gas (5) Where φ N is log neutron porosity φ Ncorr is corrected neutron porosity ρ h is hydrocarbon density