An Improved Non-Archie Fluid Saturation Workflow in Organic Shales

There are many challenges in applying Archie model to determine formation water saturation in unconventional hydrocarbon reservoirs which typically comprise stacked organic-rich source rocks with high degrees of heterogeneity in rock properties and reservoir quality. The apparent resistivity log response is usually muted due to excessive conductivity of iron rich and clay minerals in shale oil reservoirs. The characteristics of source rock reservoirs such as low porosity, variable clay types and volumes, and complex pore structures and wettability also make it a challenging task to quantify Archie parameters (m, n) for accurate petrophysical evaluation. Accuracy of Archie saturation calculations is further adversely influenced by lack of water wet formations to infer formation water salinity information in organic shale reservoirs. An improved petrophysical workflow was developed to quantify oil saturation from total organic carbon (TOC), bulk density, and porosity logs. The inversion algorithm, which is simultaneously constrained with kerogen maturity and oil density, determines oil saturation using TOC logs which are readily available from modern nuclear spectroscopy tools. No resistivity or dielectric log measurements are needed in this new workflow, which is applicable to any vendor data and can be easily implemented in any established petrophysical software platforms. The workflow has been successfully tested in a number of wells in Vaca Muerta, Argentina. Field test results show that the non-Archie workflow is capable of resolving oil saturation from kerogen and organic matter concentrations. The new integrated workflow incorporating downhole TOC measurements has a clear advantage of producing reliable and consistent oil saturation.