Early development of the Eagle Ford Shale (EFS) indicated the petroleum in the reservoir was relatively sweet, typically being produced with hydrogen sulfide (H₂S) gas in low concentrations. However in McMullen Co. TX, wells with high concentrations (>1%) are found. Mapping raw untreated H₂S gas shows a direct correlation to salt domes and subsequent deep faulting. The enigma has been the occurrence of high H₂S wells offset by low H₂S wells, not associated with salt domes or faulting. However, micro-seismic and in some cases re-processed seismic data revealed that deep faults do intersect these high H₂S wellbores. The additional data correlates deep faulting into the Edwards to high H₂S EFS wells. Deep faulting likely creates a conduit for H₂S to enter the EFS.

Building on that correlation, deep features were used to predict high H₂S wells and high H₂S was used to predict and locate deep features not previously identified. Mapping of these deep features allows for the prediction of areas with high H₂S and has led to a change in drilling and completion strategies by avoiding features associated with high H₂S.

Initially, long range plans were made with sweet EFS oil in mind. Encountering wells with large concentrations of H₂S in an otherwise sweet field has the potential to lead to operating inefficiencies, and higher OPEX and CAPEX as treatment solutions are brought into place after the fact. The best solutions take time to implement, and advance warning of high H₂S is critical in minimizing the financial impact.

A model was generated, based on the expected H₂S concentration and production forecast, that is capable of directing long term drilling and completions strategy, as well as to provide expectations for use in the construction of facilities and selection of H₂S treatment options. Drilling and completion strategies minimized the amount of H₂S that will be encountered, and the optimization of facilities reduces operating inefficiencies and OPEX and CAPEX outlays.