Optimization of Injection Brine Composition and Impact of Geochemical Reactivity in Reducing Mineral Scaling Risk During Seawater Flooding

Inorganic scale deposits pose challenges during oilfield production, especially when seawater flooding is employed for pressure maintenance and sweep. The precipitation of mineral deposits around the wells may pose a significant risk to hydrocarbon recovery by blocking flow paths, or if the reactions occur in situ deep within the reservoir, they may reduce Flow Assurance risks by removing scaling ions from the brines before they reach the production wells. This study considers these processes in a Norwegian Sea carbonate-containing sandstone reservoir, and the impact they will have on the scaling risk at the wells. Non-isothermal Reactive Transport Modelling is used to assess the impact of injector well location on temperature-dependent geochemical reactions. Anhydrite precipitation is shown to occur deep within the reservoir when the injected brine heats up. This then influences the risks associated with carbonate and sulphate scaling at producer wells during seawater flooding, where choices regarding injection water composition can be made. Seawater is the injection brine, and full sulphate (FSSW) and low sulphate (LSSW) options are considered. The extent to which CO2 partitioning from residual oil to injected water affects the carbonate scaling behaviour is modelled. The results highlight the importance of injection well location (in the aquifer or oil leg). In this study, there are two injection wells: one vertical injector below the oil water contact and one horizontal injector in the oil leg. Well location and orientation are significant in determining the advance of the thermal front; also, we observed that the mass of precipitation around the vertical injector was much more significant than around the horizontal injector. This is partially due to the average injection rate in the vertical well being higher than in the horizontal well in this case, but also, importantly, due to it being closer to the reservoir boundary, which is hot. In addition, we observed that the reactivity around the production well and the rate of scale deposition inside the well in the isothermal and non-isothermal cases were very similar. The reason for this is that the cooling temperature front does not reach the producer well, and the brine-rock interactions in the hot reservoir rocks determine the ion concentrations and drive geochemical reactions more than the reactions in cooled zones. Furthermore, the injection rates are not high enough, and the injection is not for long enough for the thermal front to reach the producer. Anhydrite precipitates in the hot reservoir zones because of the dissolution of calcium-rich minerals and the presence of sulphate in the injection brine. The concentrations of these scaling ions are, therefore, reduced when the brines reach the production well, reducing the anhydrite precipitation there and leading to almost no barite precipitation in the well. If a Sulphate Reduction Plant (SRP) is used to treat injection water, the level of desulphation required will be lower, reducing operational expenditures.