Having a power hub, to supply future Barents Sea developments, could help operators mitigate CO2 emissions – and the regulations that they could come up against. Marius Kluge Foss, of Rystad Energy, explains.
The Barents Sea is the last Norwegian oil province with anticipated future growth. From currently accounting for a mere 5% of total Norwegian oil and gas production, Rystad Energy estimates it could account for around one-third by the mid-2030s.
Several of the largest non-sanctioned fields in Norway are in the Barents Sea, of which the most notably are the three oil discoveries made up of Statoil-operated Johan Castberg, Lundin-operated Alta, and OMV-operated Wisting. The long investment and production horizons of these projects make the consideration of carbon risk highly relevant. Once developed, these fields will produce beyond the 2040s, in a period that might be associated with declining global oil demand and stricter CO2 regulations. Making decisions today to minimize this risk may be worthwhile.
Figure 1 outlines CO2 emissions associated with upstream oil and gas production on the Norwegian continental shelf (NCS).
Sources: Rystad Energy Research and Analysis
Looking ahead at accumulated emissions over the period 2040-2050, Rystad Energy expects the three Barents Sea discoveries closest to sanctioning – Johan Castberg, Wisting and Alta – to make up about 8% of total NCS emissions. Adding future volumes expected to be discovered and put into production in the Barents Sea within 2040, increases the potential of electrifying the Barents Sea to 25% of total NCS upstream emissions during 2040-2050.
The Barentshub concept
The primary challenge with electrification of fields in the Barents Sea is the vast distances. Rystad Energy addresses this issue with a suggested electrification solution for the three ongoing Barents Sea developments, Johan Castberg, Wisting and Alta, as well as potential future discoveries. The proposed solution envisages a separate host platform, a Barentshub, supplied with DC power from shore. The hub distributes AC power to the three surrounding platforms, none of which will be further away than 100km, a distance viewed as the upper bound for AC power.
The main components making up the exploration and production companies’ power demand is electric power, heating, and gas injection. These can all be served by electrical power from shore in a full electrification scenario estimated to generate an annual average power load of 298 MW/year at peak. The corresponding reductions in CO2 emissions throughout the three fields’ lifetime is estimated to 22 million tonnes.
Figure 2 illustrates the various stakeholders consisting of 1) the exploration and production companies owning and operating the facilities on the three fields, 2) the Hub owner and 3) the grid operator, in this case Statnett. Each stakeholder has its own set of considerations in the proposed setup. The exploration and production companies will be most concerned about operational performance and project economics, while the Hub owner group’s key priorities will be predictability in power demand and hence revenue.
Obstacles and cost impacts
Figure 3 outlines the combined effect on asset valuation for Johan Castberg, Wisting and Alta by switching from gas turbines to full electrification with production startup in 2023, 2025 and 2026 respectively. For the oil companies, the only negative value contribution is power opex, with capex savings, opex savings (excl. power), reduced CO2 tax and government take all contributing in the positive direction. The combined value for the three fields drops by 7% from $2.39 billion (NOK18.6 billion) in the gas turbine case to $2.23 billion (NOK17.3 billion) with electrification. This highlights the limited impairment that electrification actually has on these fields. Albeit expensive, the total implications of electrification on valuation is just a 7% reduction compared no electrification, and the future threat of carbon risk, both in terms of global carbon budgets and carbon taxes, is eliminated.
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