Comparative Study of Formation Evaluation Methods for Unconventional Shale-Gas Reservoirs: Application to the Haynesville Shale (Texas)

Abstract Petrophysical evaluation methods for shale-gas plays include mineral-based workflows that use traditional nuclear, electrical, and acoustic measurements in combination with advanced geochemical logs. This approach seems to offer the most comprehensive petrophysical analysis for unconventional reservoirs as it seeks an integrated characterization of mineralogy, organic content, porous volume, and fluid distribution. However, this method requires a significant input data set and key model parameters that may not be well known e.g. mineral elemental weight fraction end points. We anticipate variability in geochemical modeling results may arise between operators and service companies, using different model(s) and parameters, or where cross-validation with core data is not possible. The role of geochemical modeling must also be understood in the context of field-wide application, as these data are only infrequently acquired. We discuss results from three interpretation techniques applied in a Haynesville well (Texas) that were calibrated to core analyses from crushed-rock (GRI) methods. First, a multi-mineral approach that includes the standard logging suite and geochemical logs shows that independent petrophysical assessments from two vendors and those from in-house analysis are not in agreement. Second, a petrophysical model that uses resistivity and a combination of two porosity logs is proposed when only these log measurements are available. This model is readily extended to many wells with a common logging suite and may be applied in horizontal boreholes. Third, given sufficient core data across multiple wells, we apply a cluster analysis technique that provides robust results suitable for large regional studies. We compare results from each method to available core measurements and provide recommendations for further applications. In this paper, we also study the role of laboratory NMR measurements to support reservoir characterization of shale gas. Laboratory NMR measurements on preserved core samples are performed in the "as-received" state. Core NMR porosity and water saturation values are significantly different from those of the crushed-core analysis. This observation suggests that additional laboratory NMR measurements may be required for log calibration. The work described here provides an independent and critical analysis of multiple formation evaluation techniques applied to a Haynesville shale well with core and extensive log measurements. Results highlight the difficulty in developing a mineral-based model using geochemical logs that is consistent with both core and vendor deliverables. Interpretation of NMR data remains an elusive opportunity requiring mostly unknown formation-specific evaluation parameters.

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