Petrophysical Models, Their Related Assumptions And Uncertainties In Organic Shales

A substantial challenge to the petrophysical evaluation of shale gas reservoirs can be attributed to the choice of the model used for evaluation, guided by the availability of data and parameter assumptions. One of the key parameters to consider, includes total organic carbon (TOC) estimation, which remains one of the most important attributes to measure the quality of the source rock. Despite the petrophysical and geological heterogeneities in shale formations, the fundamental underpinnings are often bypassed in both choice and comparison of models, ignoring the equivalency of parameter values across the models. This invalidates the results and limits confidence in a model's robustness.

This study introduces a novel theoretical shale gas model (TSGM) aimed at advancing our comprehension of factors influencing petrophysical models. The commonly used TOC estimation methodology (ΔLogR), with a historical data set, is used as a starting point to explore the efficacy of the method by applying it to three wells in the Bowland Basin in the NW Carboniferous of England. The results show that there are issues in the application of the ΔLogR methodology, such as the picking of inherent baseline parameters, and that the level of maturity indicator (LOM) doesn’t adequately accommodate the organic and inorganic changes associated with thermal maturity. ΔLogR vs. TOC slope is simulated using TSGM; and a sensitivity analysis of TSGM suggests that inorganic porosity is a contributing factor; this has not been previously reported. Different scenarios are tested by changing the water saturation (Sw), where Sw = 1 reduces the TSGM model to the Alfred and Vernik (2013) model. The TSGM application on three wells in the Bowland Shale Formation shows that the model is generic in its application and parameters can be predicted a priori, this enables the avoidance of data overfitting, ensuring that arguments and conclusions are evidence-based.