How has Covid-19 disrupted oilfield decommissioning?

In 2020, offshore work slowed as operators cut spending and changed their priorities. This included decommissioning works, where delays have meant operators will end up paying more in the long term. A new report shows that UK fields considerably slowed decommissioning in 2020, but is that trend reflected worldwide? Matt Farmer investigates.

In March 2020, offshore operators rushed to get their workforces off their rigs. The arrival of Covid-19 in global oilfields made working offshore riskier than ever, and spending cuts meant many job losses. 

Large-scale engineering works, such as those on the Forties pipeline, faced postponement. Avoiding costly and intensive decommissioning work became an attractive choice for many, despite the greater cost in the long-term.

In November, a report from industry body Oil & Gas UK (OGUK) showed how Covid-19 had set back decommissioning on the UK continental shelf. OGUK found that companies had deferred £500m of decommissioning spending set for 2020-22.

What did decommissioning delays do to the North Sea?

The UK has one of the largest decommissioning markets in the world. In the past four years, the number of decommissioned wells has exceeded the combined total of wells in the exploration, appraisal, and development phases combined.

The effects of Covid-19 caused a 30% cut to British decommissioning spending in 2020. This cut is large, but roughly equivalent to the cuts made across all capital expenditure. While decommissioning saw similar impacts to areas such as exploration, eventually, the work must take place.

These reductions tail off rapidly, with an 8% fall to decommissioning in 2021, and a 1% fall in 2022. It also occurs against a backdrop of rapidly rising decommissioning spending.

Without work, rigs and equipment are likely to be redeployed to other regions, or scrapped, and personnel made redundant.

Operators spent an estimated total of £1.08bn in decommissioning in 2020. Over the next ten years, estimates suggest another £15bn of spending on decommissioning in the UK North Sea.

Of this, the OGUK report believes approximately 49% will go toward well decommissioning. It states: “This high percentage is due to a large quantity of activity in the shorter term compared to other areas of decommissioning.”

Well decommissioning is generally more costly than other parts of a decommissioning project because of its complex nature. The report continues: “A lack of activity in the short term will have a severe impact on the well supply chain and without work, rigs and equipment are likely to be redeployed to other regions, or scrapped, and personnel made redundant. This could cause a sharp increase in future well decommissioning costs.”

How a decommissioning downturn could have longer term consequences

When oilfield services company Valaris ran into financial trouble in April 2020, the company reported it had put many of its rigs in maintenance stacks due to lack of work. Similarly, Baker Hughes’ rig count still sits far below where it was pre-pandemic.

At the end of January 2020, the company had approximately 400 more rigs active in the US than in the equivalent week of 2021. These numbers give a very rough indication of industry activity, but still show how low activity can threaten decommissioning infrastructure.

OGUK supply chain and operations director Katy Heidenreich said: “All parts of the oil and gas business are experiencing reductions in cash flow and decommissioning is no different. Despite these pressures, the sector is in no rush to decommission.”

It was over 14/15 months to get that response out from when it first went in.

In order to support the decommissioning industry, the British Government asked the industry to suggest improvements that the government could make. After more than one year of evidence gathering, it published its Call for Evidence in December 2020. However, the industry had changed a lot in that time.

Will Rowley, interim managing director of Decom North Sea, told Energy Voice: “It was over 14/15 months to get that response out from when it first went in. All the pandemic stuff wasn’t really reflected in here, and even the context of energy transition isn’t really reflected in here either.”

The paper referred to coronavirus twice, but the authors said they believed the paper was still relevant in the context of a post-Covid world. The pandemic has also slowed governmental response to decommissioning decisions in the UK. In September 2020, it deferred a decision on the removal of subsea structures from the Brent field, the largest decommissioning project in the UK.

Could less income mean more spending on decommissioning in the medium term?

The UK is not a perfect example of the rest of the world, but it will lead global decommissioning in coming years. The UK has more offshore structures than in many other markets; almost three times more than in Norway, on the opposite side of the North Sea. 

According to analysts at Rystad Energy, the UK will absorb 80% of decommissioning spending in Northwest Europe over the next five years. Approximately four in five of its assets have already produced more than three-quarters of their resources.

Proportionately, the UK’s fields are not as mature as Denmark’s, where 90% of assets have produced three-quarters of their available reserves. However, Denmark will see only 4% of decommissioning spending over the next five years, while Norway will see 14%, and the Netherlands will receive 2.9%. At the same time, the US would see approximately one-third as much spending.

However, Rystad expects Covid-19 to lead to more decommissioning spending, not less. In May 2020, energy service analyst Sumit Yadev said: “A protracted low-price environment can potentially motivate operators to leverage low contract prices and commit to their asset retirement obligations, thus spurring decommissioning activity in the Northwest Europe region. This will also provide welcome opportunities for contractors in an otherwise gloomy oilfield services market.”

Nobody wants to be in a place where you cut off production when we could see supply limited by these capex reductions.

The company says that increased decommissioning spending could lead to limited investment in areas such as exploration. In the next five years, it expects Shell, Total, and Repsol to spend 10% more decommissioning.

However, not every industry figure believes this is the way forward. In April 2020, CEO of London-based RockRose Energy Andrew Austin gave an interview saying that he saw the value in North Sea companies extending the life of their fields in order to avoid unnecessary spending. 

He told S&P Global Platts: “We all have a responsibility to not decommission prematurely, and yes we're in a very stark world at the moment, but I see more decisions being made about delaying spending on recovering already-discovered hydrocarbons than I see on accelerating spending on decommissioning.

“Nobody wants to be in a place where you cut off production when we could see supply limited by these capex reductions.”

RockRose has previously profited by buying assets cheaply and using technology to extend their lifespans. Later in 2020, Austin Viaro Energy bought RockRose for £243m.