Recent conceptual electrification studies we have undertaken paint light on the constraints in the UKCS and highlight where the real energy is required for forward momentum. Elliot McDonald shares his thoughts.

With roughly 70% of UKCS emissions attributed to power generation, electrification presents one of the more obvious means of decarbonising North Sea production. For the most part, supporting technologies are well developed and have a proven record – both in analogous applications, such as offshore wind and interconnector power distribution, and in Oil & Gas decarbonisation applications, such as the Hywind Tampen floating offshore wind power provision to the Snorre and Gullfaks platforms and the 161 km power cable from shore to the Martin Linge development.

The only notable technological omission is the ability to convert HVDC power to AC power in a subsea setting. This would unlock possibilities for stranded deepwater assets that are otherwise bound within the limits of AC transmission distance. HVDC cables are unlikely to be suitable for the majority of dynamic applications and therefore conversion to AC is required to allow transmission over a dynamic riser section to a floating facility. This technology gap does not preclude floating assets a long way from shore from electrifying, but an intermediate distribution location will be required for power from shore.

In a UKCS setting, these facilities are very much in the minority (greenfield as well as brownfield). The majority of assets are fixed and, while conversion from DC to AC almost certainly cannot be housed on an existing operational facility due to size and weight requirements, the technology hurdle can be overcome by situating the equipment on a dedicated structure for onward AC distribution. Notwithstanding this, electrification is a very realistic opportunity for the UKCS as has already been demonstrated in the Norwegian sector.

Where the challenge really resides is in the project economics. Simplistically, the economic case can be thought of as an equation between the reward, the abatement of carbon emission and its associated value (carbon price and fuel savings), and the cost, the outlay to deploy and maintain electrification infrastructure and the cost per MWh of the power supplied.

The upside is dependent on the price of carbon. The price of carbon logically increases over time under a cap and trade scheme like the EU ETS and the UK ETS equivalent that has come in to effect following Brexit. But the rate of increase, here and globally, is very difficult to predict.

Converting HVDC power to AC power in a subsea setting would unlock possibilities for stranded deepwater assets.

Producers and partners are therefore setting internal pricing with one foot in the present and one foot in their perceived future landscape and, as would be expected with wide ranging business models, carbon projections vary considerably. The second half of the equation, and particularly the cost of grid supplied power, is a real challenge in the UKCS. The cost of electricity supplied from the UK grid is twice to three times that of Norway and even then, only a peak of 55% comes from renewable sources versus a 100% Norwegian equivalent – albeit a proportion that is increasing.

The OGA believes this cost can be reduced but still to a margin above our continental counterpart. This has led some to propose sourcing power from Norway to supply UKCS assets however there are political uncertainties that surround this approach. Layered on this cost of grid connected power supply is the infrastructure cost in relation to the power demand of a typical operating facility.

The two don’t equate. The average facility power requirement is small and compounded in the majority of brownfield cases with the need for extensive topsides modifications (and production downtime) to electrify the entirety of the demand. This disparity can be offset by having a long remaining field life – a greenfield asset designed to be operated on electric power – scale of power demand – partnership with nearby facilities – or a combination of both.

Further complicating matters is the perceived risk of a single point of failure in the power supply and, in the case of off-grid and on-grid wind concepts, the introduction of variability in the supply and regulatory hurdles that increase the time to market. You can see how the challenges start to mount, yet they are not insurmountable. Large scale electrification schemes can make sense in the UK and, depending on your perspective on carbon pricing and belief in the OGAs influence on power prices, may make a lot of sense.

UK vs Norway

The cost of electricity from the UK grid is twice to three times that of Norway

55% comes from renewable sources versus a 100% Norwegian equivalent