Australia

READ Cased Hole, a leading provider of cased hole logging services and technologies to the global oil and gas industry, has appointed Kevin Giles as its new Managing Director.

Giles has worked within the well intervention market for more than 30 years and, prior to joining READ, he spent six years at Welltec in senior management positions. Before that, he worked with Schlumberger’s electric wireline business for 20 years, progressing from offshore-based operations to key client account management and then to leadership of its UK cased hole wireline business.

The new Managing Director has now been at READ for some time, having spent the last three years as global commercial director for the company. In his new role, he will be responsible for the day-to-day management of the READ business worldwide. This includes all activities at its hub facilities in Aberdeen, Doha, Houston and Anchorage where the company supports its valued customers including oil and gas operators, major service companies, and specialist business partners.

Emerging from uncertainty

Giles said, “This is a significant time for our industry, and I am delighted to be stepping up to lead the READ business as we start to emerge from a long period of uncertainty and disruption. It’s never been more important for us to support new and existing customers and business partners looking for robust cased hole logging expertise. As an organisation, we will be wholly focused on delivering READ’s exemplary standards of safety, service quality, technical excellence and customer care.”

Tor Erling Gunnerød, Norvestor Equity Partner and Chairman of READ, added, “Kevin’s knowledge of the global cased hole logging market, the technologies involved, and the needs of oil and gas operators is second to none. I have every confidence that Kevin will continue successfully growing READ’s international reach, customer base and service portfolio, and look forward to seeing the company emerge even stronger under his leadership.”

ICON Engineering, an oilfield service company, and IK-Group, a supplier of specialist products and services for subsea and topside pipe and pipelines, have formed a strategic alliance to offer operators repair, decommissioning intervention services to the Australian offshore market.

The innovative provision of often bespoke solutions to offshore engineering problems was a common factor that led to the alliance. This partnership will combine IK-Group’s 30 year experience working in emergency repairs for offshore subsea equipment as well as ICON’s expertise installing and servicing offshore platforms, for which the company received an engineering award from the British Government.

IK-Group COO, Adrian Gamman, said, “With ICON’s local presence and IK’s track record, we believe this agreement will suit the Australian market very well. ICON’s head office is located in Perth WA, which will enable ICON to provide IK-Group’s solutions to the local market with a much quicker response time and a better understanding of the local market.”

“Specifically, this will be hugely beneficial to the end client when working on fast track deployment of emergency repairs that are synonymous with IK-Group. These are exciting times, and we are looking forward to growing this relationship in the years to come,” Gamman added.

David Field, ICON Managing Director, commented, "ICON and IK-Group have very similar innovative cultures. Our respective, and complimentary, product and services lines have all evolved from solving technically challenging and real problems, often when there simply isn't a solution anywhere.”

“At our respective Company's cores are very capable technical and management teams, experienced with execution in the field, and the proven ability to respond quickly.

“With Covid-19 restricting travel it makes a lot of sense for the two companies to collaborate by sharing our service offerings on either side of the planet. Nothing beats face to face meetings with Clients; the collaboration means there is a way to meet face to face to understand the problem and develop solutions using our combined technical horsepower.”

The Government of Australia has taken the next step in its plans to remove the Northern Endeavour FPSO facility by releasing a Request for Expressions of Interest (REOI) for Phase 1 decommissioning works, in spite of the debate that continues to rage over the decommissioning levy.

In 2019, the 170,000 bpd Northern Endeavour FPSO was shut down by the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety was found at the facility.

The task of decommissioning the infrastructure fell to owners Northern Oil & Gas Australia (NOGA) but, in late 2019 the company went into liquidation and so the facility has been abandoned, with the national government forced to maintain the facility. At the end of 2020, the government decided it was finally time to push the facility into retirement, announcing it would take on responsibility to decommission the FPSO and all related infrastructure.

In order to cover the estimated cost of US$200mn for this task, the Australian government issued a levy to the oil and gas industry to help foot the bill, which was met with disproval from many organisations such as the Australian Petroleum Production and Exploration Association (APPEA), ExxonMobil and Chevron.

Despite this, the Resources, Water and Northern Australia Minister, Keith Pitt, is pressing ahead and said that the release of the REOI was the next step in the process to disconnect and decommission the Northern Endeavour from oilfields in the Timor Sea.

A REOI from the Department of Industry, Science, Energy and Resources has been published on AusTender, inviting qualified and experienced organisations to demonstrate their capability and capacity to undertake the Phase 1 works to decommission and disconnect the FPSO from the related subsea equipment.

“The Australian Government committed to decommission the Northern Endeavour last December to remove potential future risks to the environment,” Pitt commented. “The department intends to use this process to shortlist organisations for a more detailed request for proposal stage later in the year.”

Responses to the REOI are due before 2:00pm Australian Eastern Standard Time, 29 July 2021.

A report by Rystad Energy has predicted that with Australia about to see the largest-ever wave of offshore development wells reaching the end of their producing life, the decommissioning market in region is set for a huge uptick.

The report shows that Australia’s number of ageing wells nearing retirement will jump from 160 (today) to more than 440 by 2026, with a further 172 offshore exploration wells waiting in the queue.

As a result of this, the Australian decommissioning market may exceed a total of US$40bn a figure which could even double, depending on how many decommissioning projects materialise.

“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,” said 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.

It is estimated that 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, Rystad identified a group of wells that we consider good candidates for P&A activity in the years ahead. Filtering out wells that are more likely to be identified for upcoming P&A, 440 wells are P&A candidates, the majority of which are in the Gippsland Basin.

The report continues by noting that 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 Joint Venture (GBJV). 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, Rystad has identified 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.

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 a high-cost endeavour, 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. 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.

While this could be a very costly development for operators in the region, it opens up a huge opportunity for service providers and companies involved in decommissioning operations who could see many campaigns coming their way as these wells continue to age.

The Australian oil and gas industry is, unfortunately, making all the wrong headlines at the moment as a serious row over a decommissioning levy proposed by the Australian Government continues to rage.

The tinder for this firestorm is the Northern Endeavour floating production storage and offtake (FPSO) vessel, moored between the Lamarinaria-Corallina oil fields, which was shut down by the National Offshore petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety caused by structural corrosion was found at the facility. Since the former owners Northern Oil & Gas Australia (NOGA) went into liquidation in late 2019, the national government has been maintaining the vessel until, at the end of 2020, it decided to decommission the facility and all related infrastructure once and for all.

To help cover the US$200mn expected cost of doing so, in its 2021-22 budget, the Australian Government announced it would be enforcing a levy to the Australian oil and gas industry, a decision which has so far come under heavy criticism from the sector.

Last week, Australian Petroleum Production and Exploration Association (APPEA) Chief Executive, Andre McConville, led the criticism against the Australian Government calling it an outrage that many companies who were never involved with the project will have to help pay. He also noted that such a decision could potentially hold back the Australian economy as well as the 80,000 jobs that it supports. 

Now ExxonMobil and Chevron have expressed their disapproval towards the Australian Government’s decision as well.

As reported by Reuters, a spokesperson for Chevron commented, "Chevron Australia is committed to working with the government on a decommissioning policy framework that would effectively preclude the need for this type of ad hoc, arbitrary action.”

Similarly, ExxonMobil noted that it had established a track record of executing successful decommissioning operations around the world and so shouldn’t have to shoulder the burden of covering costs for other companies as well. The company, therefore, was disappointed in the decision by the federal government, as detailed by Reuters.

While the debate will no doubt carry on for some time, the problem remains that at some point the Northern Endeavour and associated infrastructure will have to be decommissioned and dismantled. At this stage, however, who will pay for it is anyone’s guess.

The Australian government has come under fire after it announced, in its 2021-22 budget, a levy to cover the cost of decommissioning facilities around the Lamarinaria-Corallina oil fields in the Timor Sea.

In 2019, the 170,000 bpd Northern Endeavour floating production storage and offtake (FPSO) was shut down by the National Offshore petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety was found at the facility, caused by structural corrosion.

The task of decommissioning the infrastructure fell to owners Northern Oil & Gas Australia (NOGA) but, in late 2019 the company went into liquidation and so the facility has been abandoned, with the national government forced to maintain the facility. At the end of 2020, the government decided it was finally time to push the facility into retirement, announcing it would take on responsibility to decommission the FPSO and all related infrastructure.

The estimated cost of such an undertaking is an eye watering US$200mn and, to help cover this, the Australian government has now issued a levy to the oil and gas industry to help foot the bill.

The announcement has gone down poorly and the Australian Petroleum Production and Exploration Association (APPEA) Chief Executive, Andrew McConville, has led the criticism against the government. McConville was outraged that many companies that have never been involved with or benefited from the project will have to help pay, and noted such a decision had the potential to hold back Australia’s economy and the 80,000 jobs the industry supports.

McConville said, “Tonight’s announcement of a new levy on the entire (offshore) oil and gas industry is a terrible precedent and could have serious repercussions to Australia’s economy and to jobs. Everyone agrees that the Northern Endeavour needs to be decommissioned and the costs managed, but there are a number of ways that the government can do so without risking undermining investment confidence in the oil and gas industry.”

The Chief Executive added that there were other options still available, such as making the government’s current management of the operations more efficient, reducing the cost of decommissioning through collaboration, and looking at alternative funding such as selling the asset or accessing PRRT credits.

While leading the charge, McConville did note that he was glad there will be extra consultation where APPEA will be able to put forward alternatives that the government should consider to meet the costs of decommissioning. He said, “We stand ready to work with the government to look at how best to manage the decommissioning of the Northern Endeavour.”

Cooper Energy have, in their most recent quarterly report, confirmed more details for the abandonment work they have organised with Helix Energy Solutions in Australia with the announcement that they have acquired the Q7000 light well intervention rig to decommission the infrastructure in the Basker, Manta and Gummy (BMG) fields.

Earlier this year, David Carr, Senior VP of International Business at Helix Energy Solutions was joined by a host of panellists for the OWI webinar on decommissioning in Australia, where discussions focused on the substandard state of decommissioning in the region. In the session, Carr said that Cooper Energy had selected the Q7000 to perform operations for them in Australia in 2022, a move which they hoped would be the catalyst for getting on top of the decommissioning project in the country.

Cooper Energy have now confirmed this work in more detail with the announcement that the Q7000 will enter Australia waters with the first task of carrying out the decommissioning of the BMG fields, located in the Gippsland Basin. This will involve the decommissioning of seven wells and associated subsea infrastructure (pipelines and control umbilicals).

The Helix Q7000 Safety Case, a key permissioning document, has been submitted to the regulator (NOPSEMA) and is currently under review. The plan is that other regulatory documentation, including the Environment Plan and Well Operation Management Plan, will be submitted in Q4 FY21.

The BMG abandonment project is currently in the Front End Engineering Design (FEED) stage, with activities focused on selecting optimal methodologies and technologies for safe and cost-effective delivery of the decommissioning objectives. Details of scope of works, timing of execution and cost estimates will be announced at the final investment decision (FID), which is being considered in FY22.

The Q7000

The Helix Q7000 light well intervention rig has been specifically designed and built for intervention on subsea wells and abandonment activities. It is one of the newest vessels of its type, and benefits from the latest technological advances in well intervention, bolstered by its participation in the Subsea Services Alliance and array of equipment provided by Schlumberger. Its features include:

-IMO-certified Class 3 Dynamic positioning System

-Intervention Riser System, IRS 6, designed by Helix which enables access to both vertical and horizontal subsea trees in depths from c.85m to c.3000m

-Variable load capacity of c.3,000t

-ITF (Integrated Tension Frame), IRS maintenance tower, allowing for walk-to-work and safe access to well control equipment

-Large flush deck with skidding system for well intervention support equipment and tubular storage. Increasing operability by reducing reliance on offshore cranes

-Below deck twin work class ROV systems with harsh weather deployment capability

-Bulk fluids storage and pumping systems

-Wireline, Slickline, coiled tubing and cementing pumping spreads (Schlumberger)

To read more on the Q7000 and the panellists’ discussion of decommissioning in Australia, click here.

Santos, as operator of the Barossa joint venture, has announced that a final investment decision (FID) has been taken to proceed with the US$3.6bn gas and condensate project, located offshore Australia.

The Barossa FID also initiates the US$600mn investment in the Darwin LNG life extension and pipeline tie-in projects, which will extend the facility life for around 20 years. The Santos-operated Darwin LNG plant has the capacity to produce approximately 3.7mn tonnes of LNG per annum.

Barossa is one of the lowest cost, new LNG supply projects in the world and represents the biggest investment in Australia’s oil and gas sector since 2012. It is estimated the project will create around 600 jobs during the construction phase and a further 350 jobs throughout the next 20 years of production at the Darwin LNG facility.

The Barossa development will comprise a Floating Production, Storage and Offloading (FPSO) vessel, subsea production wells, supporting subsea infrastructure and a gas export pipeline tied into the existing Bayu-Undan to Darwin LNG pipeline. First gas production is targeted for the first half of 2025.

At the end of last year, Santos announced the tolling arrangements had been finalised for Barossa gas to be processed through Darwin LNG and that Santos had signed a long-term LNG sales agreement with Diamond Gas International, a wholly-owned subsidiary of Mitsubishi Corporation, for 1.5 million tonnes of Santos-equity LNG for 10 years with extension options.

Santos has also signed Memoranda of Understanding with SK E&S and Mitsubishi to jointly investigate opportunities for carbon-neutral LNG from Barossa, including collaboration relating to Santos’ Moomba CCS project, bilateral agreements for carbon credits and potential future development of zero-emissions hydrogen.

A big step forward in the Santos strategy

Managing Director and Chief Executive Officer of Santos, Kevin Gallagher, said the FID on Barossa was consistent with Santos’ strategy for disciplined growth utilising existing infrastructure around the company’s core assets.

Gallagher commented, “Our strategy to grow around our five core asset hubs has not changed since 2016. As we enter this next growth phase, we will remain disciplined in managing our major project costs, consistent with our low-cost operating model. As the economy re-emerges from the Covid-19 lockdowns, these job-creating and sustaining projects are critical for Australia, also unlocking new business opportunities and export income for the nation. The Barossa and Darwin life extension projects are good for the economy and good for local jobs and business opportunities in the Northern Territory.”

“Less than a year since we completed the acquisition of ConocoPhillips’ northern Australia and Timor-Leste assets and despite the global economic impact of a once-in-a-hundred-year pandemic, it is a great achievement to have extended the life of Bayu-Undan following the approval of the infill drilling programme and now to have taken FID on the Barossa project. I’d like to thank the Australian, Northern Territory and Timor-Leste governments, our joint venture partners and our customers for their support. I am delighted to welcome our Barossa joint venture partner SK E&S as a partner in Bayu-Undan and Darwin LNG and appreciate their support for today’s Barossa development decision,” Gallagher added.