Microbial Reservoir Souring During Engineered Water Injection with a Coupled Biogeochemical-Compositional Simulator: A Numerical Study

Abstract Reservoir souring attributed to Sulfate-reducing bacteria (SRB) poses significant challenges during waterflooding operations. Among souring mitigation schemes, engineered water injection (EWI) is deemed promising in limiting further biogenic H2S generation while enhancing oil recovery. This study is an extension of our previous work (SPE-218236-MS), where we upscale the previously generated 1D H2S bioreactor experiment model to predict the impacts of various parameters on SRB growth at a field scale. This study successfully integrates SRB activity and the effects of injection depth relevant to Oil-Water Contact (OWC) and rock wettability (intermediate-wet vs. strongly water-wet) on H2S generation into a unified 3D biogeochemical model. The bacterial growth kinetics and SRB population were simulated via partial equilibrium reaction and Monod equation incorporation. The simulation capabilities of modeling onset reservoir souring and H2S breakthrough during EWI were utilized in this study. This was possible using a reservoir simulator that offers a relatively simple yet metabolically accurate representation of the kinetic processes of bacterial populations. This model effectively captured the detailed mechanistic interactions between SRB and sulfate ions (SO42−). Additionally, the model enabled predicting the effects of injection depth relevant to OWC and rock wettability on SRB growth within a field-scale model. Even without detailed data, the findings from this study seem to align well with the established characteristics of microbial growth. Furthermore, the results demonstrated that the injection of engineered water (EW) containing sulfate ions (240 ppm) at 20°C promoted biofilm formation near the injector, enhancing SRB activity and initiating H2S production. H2S breakthrough occurred by the end of the fifth year. Afterward, H2S production declined due to reduced SRB presence and nutrient depletion, leaving some unproduced H2S near the well. Deeper injection points delayed H2S breakthrough and decreased its concentrations, highlighting the importance of careful injection depth selection to manage risks. Both wetting conditions initially showed a rapid rise in H2S concentration, with the intermediate-wet scenario achieving faster and higher oil recovery than the strongly water-wet scenario attributed to favorable mobility due to increased water viscosity. This study provides valuable insights into predicting and managing reservoir souring. This offers significant improvements to field operations and deepens the understanding of reservoir management and engineered water injection methods by addressing fundamental mechanisms that are often overlooked.