The estimation of porosity, kerogen concentration, and mineral composition is an integral part of unconventional reservoir formation evaluation. Porosity and kerogen content are the main factors influencing the amount of hydrocarbon-in-place, while mineral composition affects hydraulic fracture generation and propagation. Unconventional resources such as shale plays are compositionally complex due to great variability in rock composition and post-depositional diagenetic processes. Consequently, a reliable method that integrates results from various logging tools and core analysis is needed to determine these key petrophysical properties.Conventional well logs are typically acquired as a minimum logging program, providing geologists with the basic elements for tops identification and stratigraphic correlation. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by a minimum subset of minerals. In organic shale formations, these techniques often prove ineffective because conventional well logs are influenced to some degree by variations of mineralogy and porosity. Advanced geochemical logs, which are measurements that respond to capture and inelastic elemental composition of the rock and fluids using pulsed neutron technology, can help to understand this variability in mineralogy. This work introduces an inversion-based workflow based on probabilistic concepts to estimate total organic carbon (TOC), mineral concentrations, and porosity of shale formations using a combination of geochemical logs and conventional logs.The workflow starts with the construction of a log-based deterministic mineral model including the most likely minerals based on available knowledge and core analyses. An iterative inversion process is then applied, based on the mineral model, to estimate mineral content and porosity in addition to considering formation complexity and data quality. Uncertainties derived for each logging tool along with borehole environmental factors are formally integrated into the solution. Validation of the proposed methodology is performed using actual field data sets. A field example is supplied from a Fayetteville shale play where the workflow was successfully implemented, along with a comparison with core measurements such as XRD, XRF, SEM, porosity and pyrolysis data. The comparison shows good agreement between TOC and mineralogy derived from logs and cores.The proposed workflow integrating geochemical and conventional log measurements can reliably estimate the key petrophysical properties for unconventional reservoirs especially hydrocarbon-bearing shale. This method can be used to make decisions on optimum lateral placement.
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