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.
Traditional petrophysical evaluation methods to estimate reservoir fluid saturation rely primarily on resistivity logs and the Archie model (Archie 1942), which empirically correlates resistivity log with water saturation in reservoir rocks. In particular, the Archie model assumes water is the only electrically conductive medium in the formation, such that water saturation can be computed from the measured porosity and resistivity logs when water salinity is known. There are many challenges in applying Archie model to determine formation water saturation in unconventional reservoirs. These self-sourced shale reservoirs usually comprise stacked organic-rich source rocks, sandstones, siltstone, carbonate deposits, leading to high degrees of heterogeneity in rock compositional and textual properties. 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. Many shaly sand variants of the Archie model have been empirically established to account for clay types and deposition styles in various geographically regions and are used on an ad hoc basis to quantify water saturation in shale reservoirs (Clavier 1977, Poupon 1972, and Waxman 1968). Tight porosity and varying formation water salinity profiles in source rocks lead to large reservoir fluid volume uncertainties.
