Determination of the Impact of Sulphate Concentration on Seawater Injection in a Brazilian Pre-Salt Field Using Reservoir Reactive Transport Modelling

Due to the mixing of sulphate ions in the seawater with barium, strontium, and calcium ions in the formation water, the spread use of seawater as a pressure support fluid during secondary oil recovery within sandstone and carbonate reservoirs may lead to the precipitation of inorganic scales. Oil production may be significantly and adversely impacted by the formation of these salts within the reservoir and, more concerningly, in the vicinity of the wellbore and in the production string itself. It has been studied that in situ geochemical reactions occur during the waterflooding process due to water-rock and water-water interactions (CARDOSO et al, 2023). Calcium sulphate scale may form in high temperature chalk reservoirs that undergo seawater injection as a consequence of mineral reactions involving calcite dissolution and magnesium rich carbonate precipitation. One important factor in the precipitation of calcium sulphate (gypsum or anhydrite) is temperature (with has low solubility at high temperature, especially for anhydrite). One of the scaling risk control strategies is to alter the injection water composition to lower the SO42- concentration, such as by injecting low sulphate seawater from a sulphate reduction plant (SRP). Increasing the tolerance of the SRP requirement can not only save operation expense but also free up limited deck space on FPSOs (Wright et al., 2008) PRIO is developing a pre-salt field in the north of the Campos Basin. It has been demonstrated that reactions in the reservoir may strip SO2- from the injection brine stream, helping to mitigate the scaling risk. A mineral deposition reaction deep within the reservoir is the mechanism responsible for removing sulphate from the brine, thus reducing the scaling risk for anhydrite and celestite where the injected brine mixes with formation water within and adjacent to the producers. Because the mineral deposition takes place deep within the reservoir where the fluid throughput to rock volume ratio is relatively small (typically order <10 pore volumes), there is no observable impact on flow (Macka et al., 2014). The fact that the field is at temperatures higher than 110°C is critical in this regard, since CaSO4 is relatively soluble at downhole water injection temperatures (<50°C), but above 90°C the solubility decreases significantly. The amount of Ca2+ that drives the CaSO4 reaction in such system can be significantly influenced by the presence of bicarbonate (HCO3-) in the brines and the reactions with the carbonate rock. The system's flow configuration is another crucial element. The effects of distance between injector-producer pairs, injecting seawater into high permeability areas, including fractures, differ from those of injecting water into the oil leg. In the study, the injectors are positioned to inject seawater directly into the aquifer, only for pressure support. This configuration could impact the sulphate scaling risk at the production wells and how it evolves as the field ages. In order to assess the effects of injection water composition, temperature, rate, and injector locations relative to the producers on calcium and strontium sulfate scaling risks in the Field, a reactive transport model has been established using CMG GEM (Yisheng et al., 2016).