PETROPHYSICAL MODELLING IN ORGANIC RICH SOURCE ROCKS

Abstract

Rapid depletion of conventional reservoirs globally has shifted the focus towards unconventional hydrocarbon resources like shale formations that are rich in organic content. Concerted efforts are directed towards unravelling the resource potential of these unconventional formations and hence a method is presented to compute the potential of a deep seated organic-rich source rock in terms of hydrocarbon saturation. The sequential workflow designed involves correlation of well logs and the core measurements using XRay Diffraction (XRD) and GRI Dean Stark extraction data. Amount of insoluble organic matter known as ‘kerogen’ affect the hydrocarbon generation potential of a rock formation depending upon its thermal maturity and chemical composition (Hydrogen Index-HI versus Oxygen Index-OI). Maturity of kerogen to the time it undergoes thermal cooking and its type decides the type of hydrocarbon a source rock is capable of generating. Thus porosity computation must include concentration of organic content in the grain matrix and hence porosity model developed by Sondergeld (2010) is used for Petrophysical modelling. An Empirical relation has been developed between the volume percentages of minerals and grain density (without kerogen) to upscale grain density which is a prerequisite input parameter to obtain continuous porosity trend with depth. The water saturation (Sw) determined using Simandoux model (1963) that used the volume of shale (Vsh) accounted for overestimated saturation obtained using Archie’s (1942) law and gave best correlation with GRI measured saturation. The petrophysical properties like porosity and saturation predicted using logs have correlated very well with the laboratory measurements demonstrating the robustness of the model.