The Operator and the license partnership have set an extremely high ambition for recovery from the Johan Sverdrup field, even before a barrel of oil has been produced. How is this possible? This paper describes the characteristics of the reservoir, as well as early assessments and investments for improved oil recovery (IOR) to ensure flexibility. In addition, data acquisition, reservoir monitoring, new technologies and digitalisation, as well as new ways of working are addressed. This will be the key enablers for a recovery of more than 70% of the field’s oil resources. Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS) with a recoverable volume range of 2,2 to 3,2 billion b.o.e. The reservoir is characterized by excellent reservoir properties with a strongly undersaturated oil. The primary drainage strategy is water flooding, including re-injection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil production plateau. The field came on stream in October 2019. Going back to the early stages of the Johan Sverdrup field development, it was obvious from the start that this would be an independent development solution with a long lifetime. Given the excellent reservoir, this was considered as a unique opportunity to plan for a high resource exploitation, and make sure that future business opportunities in this context could be utilized in a technical and economically attractive way. A very early screening was conducted to investigate which IOR measures should be further matured. With subsurface evaluations as the base, this maturation also included assessments on technical feasibility and potential implications for development solutions. The objective was to ensure sufficient flexibility in early field design. It also implied that the Johan Sverdrup license had to consider pre-investments prior to any implementation decision. Data acquisition and reservoir monitoring strategies were also started early on, which e.g. led to a full field Permanent Reservoir Monitoring (PRM) decision, with installation starting summer 2019. This gives a baseline for parts of the field before production start, and when completed in 2020 it will be the world’s largest fiber based PRM system. Fiber optics are also installed in the wells. In addition, a dedicated observation well is part of the development plan. The idea is that PRM and fiber data results, in addition to repeated logging in the observation well, will be key information to evaluate business cases for future IOR or new technology measures. Digitalisation has also been a key aspect of this, and several subsurface-focused digitalisation initiatives have been implemented during the field development, giving the operator the opportunity to implement new ways of working and enabling new ways of cooperation in the partnership as data and applications are shared within the owner group in a digital setting. The overall objective of digitalisation in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir – and hence value of the Johan Sverdrup field – for the license owners.

Summary The Johan Sverdrup field will, at maximum, contribute 25% of the total oil production from the Norwegian Continental Shelf (NCS). Plateau production from the fully developed field is estimated at 550,000 to 650,000 BOE/D. 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 over the composition of formation water made the decision to inject normal seawater or low-sulfate seawater into the reservoir for pressure support a challenge. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulfate-rich with negligible barium. This was suspected to be an artifact of drilling-fluid contamination, and corrections were applied to obtain representative estimates. These estimates confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulfate-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/or (b) interactions with the underlying Zechstein group (anhydrite). The focus here is on issue (b) because 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 sulfate- 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 reinjection, and low-salinity/low-sulfate-water injection. Moderate strontium sulfate (SrSO4) and calcium carbonate (CaCO3) scalings are expected in the production wells. If third-party barium-rich waters are tied in, the topside barium sulfate (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 a sulfate-removal plant. Produced-water reinjection will gradually replace seawater to minimize environmental impact. Downhole scale-inhibitor injection has been recommended to protect the upper completion.

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 (Ͻ6 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 (SrSO 4 ) and calcium carbonate (CaCO 3 ) scaling are expected in the production wells. If third party barium-rich waters are tied-in, the topside barium sulphate (BaSO 4 ) 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.

The sheer size of the 2.7-billion-barrel field and expected operations of more than 50 years, make Johan Sverdrup an exciting place to develop the solutions of the future. As such, the Johan Sverdrup field development has been called the digital flagship for the operator. Being a ‘flagship’ means Johan Sverdrup is not only meant to be a vehicle for digital innovation to improve safety, value-creation and carbon efficiency for the field itself, but the field development is also meant to drive digital solutions and ways of working that have the potential to be scaled-up for the benefit of the operator as a whole. This paper starts by setting out the main digital focus areas for the Johan Sverdrup development, but drills down on exploring the areas where Johan Sverdrup is demonstrating real and tangible impacts already today. Examples include efforts to mature technology for automatic production optimization, a number of new pipe and seabed technology solutions (including fiber-optic PRM, fiber-optic monitoring of wells), and the step-wise development of a digital twin for Johan Sverdrup that will gives the opportunity to model and visualize key parts of the field. The paper describes the ‘digital field-worker’ at Johan Sverdrup which is changing the way of working, both during the construction and completion phase, but also during operations. This ranges from efforts to automate and digitalize work processes offshore to more innovative solutions. Examples of the latter include Echo – a multi-player digital twin solution allowing real-time visualization and collaboration between onshore and offshore – as well as the iterative development of anomaly detection models (utilizing machine learning and artificial intelligence) to move from condition-based monitoring towards predictive maintenance.