The interplay between microbial reservoir souring and barite scale formation in hydrocarbon reservoirs

The injection of seawater into a hydrocarbon reservoir (seawater flooding) as a secondary or tertiary oil recovery method is associated with two possibly significant challenges. First, the formation and deposition of various types of scale may happen due to incompatibility between the injection seawater and formation brine. Especially, the addition of sulfate ions may trigger the formation of various types of sulfate scales (e.g., barium sulfate, stron-tium sulfate, and calcium sulfate). Second, microbial reservoir souring may happen due to the activation of Sulfate Reducing Bacteria (SRBs), which reduce sulfate ions to hydrogen sulfide. This is mainly a result of a drop in temperature in the reservoir, the addition of sulfate from the seawater to the reservoir, and the presence of Dissolved Organic Carbon (DOC) coming from reservoir hydrocarbon. Since both these processes include the consumption of sulfate ions, a competition is expected to happen between them. Especially, there is a concern about whether an efficient mitigation strategy for souring (e.g., nitrate treatment) will result in less consumption of sulfate ions and in turn more formation of sulfate scales. This study tests this theory and investigates the effect of souring intensity and mitigation on the severity of barite scale formation inside the reservoir. In this study, a non-isothermal multi-component bio-chemical model to simultaneously simulate both the processes is devel-oped. Several simulation cases in one and two dimensions are investigated in different conditions in order to study the effect of three influential parameters, namely sulfate ion concentration in the injection sweater, the DOC content of the reservoir hydrocarbon, and injection flow rate on barite scale formation, microbial reservoir souring, nitrate treatment, and the interplay among them. The results show that the effect of barite scale for-mation on reservoir souring is small (a maximum of 4 percent reduction in the total generated hydrogen sulfide) whereas reservoir souring and nitrate treatment significantly influence barite formation. Depending on the case, the presence of souring can cause a complete removal of barite scale especially around the production well (positive effect) or a maximum of 8 times increase in barite scale amount around the production well (negative effect). Moreover, in all cases, with a more efficient nitrate treatment, although less hydrogen sulfide is generated inside the reservoir (up to a full removal of souring), the generation zone moves closer to the production well. Therefore, an insufficient nitrate treatment may cause an earlier hydrogen sulfide production from the pro-duction well (up to twice as early). Several other trends observed in the set of results are also presented in this paper.

Automated summary

Seawater flooding as a secondary or tertiary oil recovery method may face challenges of scale deposition and reservoir souring. This study finds that scale formation has a minor impact on reservoir souring, but reservoir souring and nitrate treatment significantly influence scale formation. Moreover, more efficient nitrate treatment leads to a closer proximity of the hydrogen sulfide generation zone to the production well.