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ExxonMobil ordered to start decommissioning work on offshore Australian assets

US supermajor also hit with improvement notices after corrosion issues were discovered at two of its producing platforms in the Gippsland basin

21 May 2021 5:04 GMT UPDATED 21 May 2021 9:02 GMT

US supermajor ExxonMobil has been ordered to start preparing to decommission ageing infrastructure in Australia’s Gippsland basin, just months after it cancelled the planned sale of the assets.

Australia’s National Offshore Petroleum Safety & Environmental Management Authority (Nopsema) issued ExxonMobil subsidiary Esso Australia with a general direction this week to commence decommissioning activities for all structures, property and equipment no longer in use.

The direction from the regulator ordered the US operator to complete all preparatory decommissioning activities and commence the topsides dismantling campaign “as soon as reasonably practicable”, and no later than 30 September 2027.

It also gave ExxonMobil the same deadline to plug or close all wells associated with the assets.

Nopsema has listed a total of 10 ExxonMobil-operated platforms no longer producing in the Bass Strait: Whiting, Mackerel, Fortescue, Kingfish A and B, Flounder, Bream A and B, Dolphin and Perch.

The number of wells associated with the facilities totals 173, while Nopsema has also identified seven suspended or temporarily abandoned wells in ExxonMobil’s permits not associated with a production platform.

Independent review
ExxonMobil will also need to commission an independent review of decommissioning activities to identify opportunities and propose measures to reduce the timeframe for commencing and subsequently completing all necessary decommissioning activities.

It will then need to submit a report to Nopsema within 180 days of the 20 May general direction, detailing the outcomes of the review and the recommended measures.

The operator will also be required to report annually to Nopsema on its progress until all decommissioning activities have been completed.

In response to the general direction issued by Nopsema, an ExxonMobil spokesperson told Upstream the company is committed to ensuring its decommissioning activities are performed in accordance with all applicable regulatory requirements.

“Decommissioning of offshore facilities is a complex activity that requires many years of extensive planning and precise delivery whilst continuing to deliver gas to the domestic gas market,” he explained.

“Our detailed planning is well under way and we have already started much of the early work required — over the past two years we have invested more than A$300 million (US$232.8 million) to plug and abandon wells at Mackerel, Blackback and Whiting.

"Over the next two years we will spend more than A$150 million on further plug and abandonment work, including the recent introduction of a second platform based rig into the Gippsland basin.”

The spokesperson added that ExxonMobil would leverage its company-wide experience in “safely and effectively” decommissioning assets across its global portfolio when it came to its assets in the Bass Strait.

Ageing assets
ExxonMobil commenced production from the Gippsland basin in 1969, with the installed infrastructure since then including 421 wells, 19 platforms, around 600 kilometres of subsea pipeline and four subsea facilities, with another soon to be installed.

However, Nopsema noted that production has ceased at 10 platforms, three subsea facilities, 16 pipelines and over half of all wells drilled, with output expected to cease at a further six platforms and seven pipelines by 2025.

“It is Nopsema’s view that Esso’s ability to decommission appropriately is increasingly at risk the longer the period that elapses between cessation of production and completion of decommissioning activities,” Nopsema noted in its direction.

“Further it [is] Nopsema’s view that risk to safety of people at facilities and environmental risks and impacts are also observed to be increasingly challenging to manage the longer non-producing facilities remain.

“Nopsema is of the opinion that, while Esso has provided an overview of the decommissioning activities proposed, the level of planning and timing proposed for removal is not commensurate with the scale of decommissioning activities required.”

The direction follows inspections of several non-producing platforms between March and May, which led Nopsema to conclude the operator was not carrying out adequate field maintenance activities at the Perch and Dolphin facilities.

Corrosion at producing assets
Nopsema also hit ExxonMobil with another general direction this week over its producing facilities, requiring it to validate the integrity assessment of all corrective maintenance work orders that are beyond their initial scheduled completion date.

It comes after Nopsema carried out an inspection of the Tuna and Tuna West facilities between 30 March and 1 April and found ExxonMobil’s facility integrity programmes were only partially compliant.

It also saw the regulator issue the operator with three improvement notices for three separate corrosion anomalies, including corrosion on deck grating on the Tuna platform, as well as corrosion to deck grating support structures at West Tuna and corrosion of structural support elements to the facility’s helideck.

“Further structural integrity risks may exist elsewhere on the facilities inspected (Tuna and West Tuna) but also on other producing facilities currently operating under the titleholders' various registered titles,” Nopsema stated in one of the general directions issued Thursday.

ExxonMobil's producing platforms include the Barracouta, Malin A and B, West Tuna, Halibut, Cobia, West Kingfish, Tuna and Snapper.

ExxonMobil operates the Gippsland jo--t venture in a 50:50 partnership with Australian resources giant BHP.

Legislation changes halt Gippsland exit
BHP is currently looking to offload its share in the jo--t venture, while ExxonMobil had also been looking to offload its operating stake in the aging assets, but pulled the plug on the sale in November last year.

ExxonMobil's decision came following a letter from Australia’s Resources Minister, Keith Pitt, warning the company of proposed legislative and regulatory changes that would ensure a higher level of financial scrutiny and the introduction of a trailing liability regime.

This would mean that ExxonMobil could have still found itself liable for the cost of decommissioning the assets, even if it was able to sell them to another company.

The planned legislative changes follow the collapse of Northern Oil & Gas Australia (Noga), which bought a 100% interest in the Laminaria and Corallina oilfields, as well as the Northern Endeavour floating production, storage and offloading vessel from Woodside Petroleum in 2016.

Noga went into administration last year, leading to an unprecedented event in Australia’s offshore industry and leaving the federal government as the owner of the assets and holding the decommissioning bill.

In the federal budget announced earlier this month, it was revealed the government was now proposing a temporary levy on all offshore production to help fund the decommissioning work, meaning the oil and gas industry will foot the bill as opposed to Australian tax payers.

https://www.upstreamonline.com/safety/exxonmobil-ordered-to-start-decommissioning-work-on-offshore-australian-assets/2-1-1013822

We are required by the Australian government to decommission our non-producing offshore assets. Our wish list to convert our non-producing offshore assets (i.e. Gippsland) to carbon capture and storage sites is to avoid paying ~$40 billion in decommissioning charges. We tried to sell the Gippsland assets in 2021 but there were no buyers.

https://www.rystadenergy.com/newsevents/news/press-releases/with-hundreds-of-australian-wells-stopping-production-soon-a-multi-billion-pa-market-emerges/

With hundreds of Australian wells stopping production soon, a multi-billion P&A market emerges

June 9, 2021

Australia is about to see its largest-ever wave of offshore development wells that reach the end of their producing life and need to be for decommissioned. This task is both adding headaches for producers and creating a multibillion-dollar opportunity for plugging and abandonment (P&A) suppliers. A Rystad Energy report shows that Australia’s number of such wells will jump from 160 today to more than 440 by 2026, with a further 172 offshore exploration wells waiting in the queue.

The Australian decommissioning market may exceed a total of $40 billion due to the country’s sizeable offshore P&A liabilities and its non-producing onshore assets. The figure could even double, depending on how many decommissioning projects materialize.

“Recent developments have made it more difficult for operators to sidestep decommissioning obligations by selling ageing assets, as the market appetite for such assets is drying up. Many producers will have to deal with the issue in coming years, with ExxonMobil having the lion’s share of liabilities in Australia,” says Jimmy Zeng, senior analyst at Rystad Energy’s upstream team.

Rystad Energy’s analysis of the P&A potential takes into account the production status of each operator’s offshore wells, the likelihood of producing fields ceasing output in the coming five years, wells that have been already suspended but not yet abandoned, along with partially abandoned wells. While development wells make up the bulk of the total, exploration wells are also in need of P&A to a lesser extent even though we do not expect strong exploration growth in Australia in coming years.

Turning our attention to development wells, we estimate 890 offshore wells in total were drilled in Australia before 2015, of which 108 have been permanently abandoned. Of the 782 wells not yet abandoned, we have identified a group of wells that we consider good candidates for P&A activity in the years ahead. We define a well as a collection of one or more wellbores with the same top-ho-e location.

Filtering out wells that are more likely to be identified for upcoming P&A, we end up with 440 wells that are P&A candidates, the majority of which are in the Gippsland Basin.

The dominance of the Gippsland basin is to be expected given the legacy of offshore development in the region, driven by ExxonMobil and BHP’s Gippsland Basin Jo--t Venture (GBJV). The area has been a key source of domestic gas supplies going back to 1964, and output is expected to go into long-term decline over the next decade.

Within the Gippsland group, most wells are located on fixed platform facilities, while in other basins the distribution of facility types is more mixed. New resource developments in the Gippsland Basin are becoming more capital intensive, but the outlook for P&A opportunities in the area should prove attractive to service suppliers.

In the North Carnarvon Basin group, we see an age distribution that shows non-producing wells are relatively “younger” than those in the Gippsland, with the majority being no more than 20 years old. Even so, various measures intended to ensure operators fully decommission facilities and wells are likely to provide a tailwind for service suppliers seeking P&A mandates in the North Carnarvon basin as well – spurred by the industry controversy over Northern Oil & Gas’s inability to fund its decommissioning of the Northern Endeavour FPSO and associated wells.

Given its large legacy position in the Gippsland, it is no surprise that ExxonMobil leads the way in its decommissioning liabilities, with a rapid increase in the number of wells likely to cease production over the next five years. While this is indubitably a high-cost endeavor, we note that most of these wells are platform-based, where per-well abandonment costs are likely to be significantly lower than for subsea wells. Furthermore, regulatory pressure on ExxonMobil to decommission these wells has increased significantly lately.

Outside of ExxonMobil’s high well burden, operators Santos, Woodside, BHP and Vermillion Energy will also experience growing decommissioning obligations in the next five years, measured by the increase in wells within our “potential for P&A” grouping. Woodside and BHP have mostly subsea wells in this category, which could mean their decommissioning bills will be higher on a per-well basis. Woodside recently communicated its intention of starting abandonment of up to 18 subsea wells on the Enfield field from 2022 to 2024.

More insights from Jimmy Zeng on Australia and its future as one of the world’s top LNG suppliers will be available during our “Our Business - Progress or Pivot?” session on 16 June at 11:15am AWST at APPEA 2021. Meet us at booth #228 to learn more.

For more analysis, insights and reports, clients and non-clients can apply for access to Rystad Energy’s Free Solutions and get a taste of our data and analytics universe.

There's an upstream business as well. Google esso australia...

Nice long trips in business class and a great fully company paid travel destination. Chi Ching for all those involved.

Do you think there is anyone left at ExxonMobil who can distinguish between a right and a wrong?

Are you really that stupid?