The Johan Sverdrup Field – Origin of Sulphate-Rich Formation Water and Impact on Scale Management Strategy

Abstract

Abstract The Johan Sverdrup field will at maximum production contribute 25% of total oil production from the Norwegian continental shelf. Geochemical formation water interpretation and development of a scale management strategy have been performed to ensure high well productivity and process regularity of the field. Uncertainty in the formation water compositions challenged the decision to inject normal seawater or low sulphate seawater into the reservoir for pressure support. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulphate-rich with negligible barium. This was suspected to be an artefact of drilling fluid contamination and corrections were applied to obtain representative estimates. These confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulphate-rich (94–746 mg/L) and barium-depleted (<6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and (b) interactions with the underlying Zechstein Group (anhydrite). The focus here is on issue (b), as a detailed evaluation of local/regional aquifer movements in geological time, communication patterns and flow restrictions is beyond the scope of this paper. Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein Group was present. Initially, there were concerns about the scaling risks associated with mixing sulphate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full field development and scale strategy do not need to consider barium-rich water. Scale predictions were performed for various strategies; formation water production, seawater injection, produced water re-injection and low salinity/low sulphate water injection. Moderate strontium sulphate (SrSO4) and calcium carbonate (CaCO3) scaling are expected in the production wells. If third party barium-rich waters are tied-in, the topside barium sulphate (BaSO4) scaling risk increases. This work has shown: Careful evaluation of formation water samples/analyses reduces uncertainties associated with water compositions and increases confidence in results and decisions.Underlying geology can influence formation water compositions.Good quality water sampling is important for later phase field development and scale management. The implications for field development are: Seawater will be injected into the reservoir for pressure support with no need for sulphate removal plant.Produced water re-injection will gradually replace seawater to minimize environmental impact.Downhole scale inhibitor injection has been recommended to protect the upper completion.