New approaches to distinguish shale-sourced and coal-sourced gases in petroleum systems

Current approaches relating thermogenic gases to either shale source rocks (predominantly type II kerogen) or coal source rocks (predominantly type III kerogen) are not reliable and not globally applicable. This is because these mostly empirical approaches were developed using small poorly-constrained datasets from limited locations. The evaluation of a large global dataset of molecular and isotopic properties of gases from unconventional shale and coal reservoirs suggests that two genetic diagrams based on stable carbon isotopes of methane and ethane, delta C-13-C2H6 versus delta C-13-CH4 and delta C-13-CH4 versus Delta(delta C-13-C2H6 - delta C-13-CH4), provide the best separation of shale-sourced and coal-sourced gases. Newly designated genetic fields and shale/coal separation lines on these diagrams were tested and validated using data from five petroleum systems with, likely, only shale (class B and A organofacies) source rocks (the Maracaibo Basin in Venezuela, the Guajira Basin in Colombia and the Rub Al Khali Basin in Iran) and only coal (class F organofacies) source rocks (the Southern Permian Basin in Germany and the Sichuan Basin in China). The practical usefulness of this new approach to gas-source correlations was demonstrated in two case studies from petroleum systems with debated source rock organofacies (the Mozambique Basin in Mozambique and the Indus Basin in Pakistan). These better constrained and more reliable diagrams with genetic fields and shale/coal separation lines represent a new tool for the evaluation of petroleum systems.

Automated summary

Current methods correlating thermogenic gases with shale and coal source rocks are unreliable and not globally applicable. A new approach based on stable carbon isotopes provides a more accurate separation of shale-sourced and coal-sourced gases, which has been tested and validated in several petroleum systems.