Can North Sea rigs cut emissions and stay profitable?

The North Sea Transition Authority (NSTA) and green campaigners say oil and gas producers in the region will need to spend big to meet government emission reduction targets by 2030, potentially rendering some unprofitable, even as the government pushes for a ramp-up of production.

Average UK North Sea emissions are higher than those from nearby offshore regions because of the age of the assets, while recent reductions have largely come from closures and limits on flaring rather than major operational advancements. 

The 2030 target, a step along the way to net zero, is for the region to only produce 9mn tonnes a year of total carbon dioxide equivalent emissions, a measure that includes methane and nitrous oxide. Last year, roughly 14mn was emitted, according to the government regulator's estimate.

But a recent report from Carbon Tracker, a climate-focused think tank, said asset profitability could start to come under threat from a mandated 2030 emissions target. “The North Sea’s oil and gas regulator has already cracked down on emissions from existing fields, which has come at significant cost to producers,” the report said. “Both the need for and cost of action will increase over time, as the carbon intensity of fields increases dramatically as fields mature.” 

Carbon Tracker said the vast majority of North Sea production was from the most emissions-intensive fields, which are those that have already had three-quarters of their recoverable reserves extracted. 

The North Sea Transition Authority (NSTA) has cast doubt over the trajectory to 9mn tonnnes of CO₂ by 2030. This is “not expected to be met without the implementation of further abatement initiatives” or even more project closures, a report said last year.

But Stifel analyst Chris Wheaton suggests that closures and a limit on venting will ensure the industry meets the target. Venting is the release of natural gas into the atmosphere, while flaring involves burning the gas. Around 80 per cent of operational emissions come from powering platforms, while 16 per cent is from flaring and 4 per cent from venting, according to the NSTA. 

Owners of mature assets, such as Harbour Energy (HBR) and Serica Energy (SQZ), are likely to need to put a particular focus on emission reductions in the years ahead.

Serica reported last year that its Bruce hub had an emissions intensity of 15.1kg per barrel of oil equivalent (boe) in 2022, while its Triton asset was higher at 17.7kg CO₂ equivalent (CO₂e)/boe. These are below the offshore North Sea average of around 21kg/boe, but will still require investment if they are to hit the NSTA goals. Emissions vary widely within UK waters overall, ranging from 33kg/boe in the East Irish Sea to 19kg/boe in the cental North Sea.  

Harbour owns some of the most carbon-intensive operations in the North Sea, according to NSTA data. The Armada field's emissions intensity is around 74kg/boe of CO₂e. There are larger emitters – the privately owned Tiffany platform has emissions of 118kg/boe – but the age and scale of Harbour’s operations mean it is a major contributor, even once its smaller, higher-emitting platforms go out of production. Its average CO₂ equivalent intensity in 2022 was 20kg/boe. 

Rich Collet-White at Carbon Tracker says closures would only do so much from here on out. 

“There's a question over [whether operators have] already got the low-hanging fruit, and what's going to happen in future years,” he said. “Is there also greater policy or regulatory risk coming down the line with more stringent methane emission restrictions?”

The potential election of a Labour government later this year could bring more onerous restrictions, albeit the opposition party has also looked to reassure businesses recently to encourage investment. 

Carbon Tracker analyst Maeve O’Connor says there is a further question around the likelihood of a steep decline in North Sea production.

“Most companies, if they're to do no new developments, will have 20 per cent of the production they have today by the 2030s,” she said. “The inference from that is that, unless they're very upfront about winding down their production, the likelihood is that they will continue to expand into new projects.”

Going electric

Stifel analyst Chris Wheaton says the 2030 goal is easily achievable on the current trajectory, largely through closures.

Around 2.5mn tonnes of emissions will disappear via the closure of the oldest projects, assuming they run at 20kg CO₂/boe intensity. That would leave a further 1mn tonnes reduction to hit the goal. "Current emissions from methane venting are around 1-1.5Mte CO₂e, so eliminating this venting would get the North Sea over this threshold," Wheaton adds. Flaring and venting levels have already tumbled, and are around 30 per cent of the 2001 level. 

A Carbon Tracker report published in February pointed to the need for electrification, which would replace natural gas burning or diesel power.  Wheaton notes that electrification costs will vary depending on the location of the platform, with a central North Sea field costing $200mn-$250mn (£160mn-£200mn) to electrify from shore.  

“Fields need both investment incentives to do so, and also enough time left in [their] producing life to recoup the investment,” he says. “I think maybe 20-25 per cent of current UK [North Sea] production could feasibly be electrified.”

The NSTA’s 2023 report said electrified platforms were likely to come in the next stage of North Sea development. Its base case estimate is for eight electrified assets by 2030, which would knock out 1.3mn tonnes of annual CO₂ equivalent emissions, or 10 per cent of the 2023 total. Kistos (KIST), a Dutch and UK North Sea operator, has one electrified platform which produced emissions of just 0.279kg/boe in 2022.

Fields further out from shore would have to look to offshore wind or hydrogen for electrification.

Wheaton updated his valuation model for Serica last week and also looked closely at the emissions trajectory. “Carbon intensity on both absolute and per-boe basis is likely to fall significantly from here, we think, through ongoing investment in electrification to reduce emissions from power generation, which are the largest source of emissions, especially on the Bruce platform,” he says.

Beyond the cost, there are technical challenges involved in hooking platforms up to mains power or renewables. "The first is ensuring an uninterrupted supply of power to the assets when using variable renewable generation technology," said Nicholas Skeen from energy consultancy DNV last year. "The second is retrofitting brownfield installations to receive power from subsea cables which would need to be transformed to the appropriate levels used onboard." 

Skeen pointed to Norwegian projects where the intermittancy issue had been solved by maintaining a mix of energy sources. Equinor (NO:EQNR) says its Snorre and Gullfaks fields are one-third powered by a new floating wind array that cost around £560mn. Equinor is also developing the major Rosebank field in the North Sea, but has talked of electrification as a potential add-on rather than an integral part of the plan. The company will, however, spend £80mn on "modifications to support future electrification" of the field's second-hand floating production, storage and offloading vessel, and has said electrification is "technically feasible". 

Overall, though, the technology is still up in the air. Even Equinor says so. The shift will happen when the "technology is qualified and matured [and] viability is confirmed", the company said. Another two west-of-Shetland fields could then be electrified alongside Rosebank, BP's (BP.) Clair field and Ithaca Energy's (ITH) Cambo. This would knock out significant North Sea emissions, although the impact would be limited without renewable energy feeding into the underwater cables.