Reach Subsea’s pioneering Uncrewed Surface Vehicle (USV) in on-route to Australia to deliver subsea services for Woodside Energy.
Reach Remote 2 will perform reservoir monitoring on the Scarborough gas field by utilising the company’s gWatch technology. gWatch, used widely across Norwegian gas fields, measures time-lapse gravity and seafloor deformation to detect small changes in mass and pressure. The precision measurements significantly reduce uncertainty in gas reservoirs and aquifer influx to enhance workflows and support accurate production forecasts.
Reach Remote 2’s operation in Australia will demonstrate the USV’s ability to reduce offshore personnel operational risks, cut costs and reduce environmental impact compared to traditional crewed vessels.
Reach Subsea’s CEO Jostein Alendal said, “Seeing the Reach Remote 2 vessel sail ‘down under’ to deliver world-class services to a company like Woodside Energy is a proud moment for all of us at Reach Subsea. This project clearly demonstrates that the transition to a robotic future is not a vision – it is happening now. We are reducing HSE risks by removing personnel from hazardous environments, reducing operational costs and cutting the carbon footprint of offshore activities by up to 90%.
“It is a major leap forward for the industry and a testament to what innovative technology can achieve.”
The deployment marks the beginning of Reach Subsea’s Inspection, Maintenance and Repair (IMR) operations in Australia, and highlights the company’s expanding global presence.
Ace Well Technology, in collaboration with Expro and Archer, has successfully completed the first well deployment of the Ace Control Line Clamp (ACLC) using Expro’s Remote Clamp Installation System (RCIS) on the Norwegian Continental Shelf (NCS). This marks a significant milestone in advancing well completion operations through automation, combining precision engineering and operational efficiency.
“The ACLC was engineered with the objective of maintaining mechanical robustness while enabling remote installation under dynamic rig conditions. By leveraging our proven ratcheting mechanism, we’ve developed a clamp that delivers consistent holding force, precise alignment, and rapid installation - whilst significantly reducing red zone exposure. This first deployment confirms the system’s performance in real-world conditions and validates the design choices that underpin its functionality,” said Anbjørn Kaurstad, technology manager at Ace Well Technology.
The operation was carried out with Archer as the drilling contractor, who welcomed the new system for its operational consistency and technical advantages. “We’re excited to join this breakthrough – hands-free completion enhances safety and efficiency by reducing manual risks and delivering more consistent results. Upholding strong QHSE standards is vital to every project, and this innovation helps us protect our team while improving the quality of our deliveries,” said Bjørn Christensen, One Archer Manager FLX.
Built on Ace’s proven Ace Ratchet Collar (ARC) technology, the ACLC automates control line clamp installation while maintaining reliability under rigorous well conditions. The combined ACLC and RCIS system performed seamlessly during the first deployment, achieving a peak running speed of 15–16 joints per hour. All clamps functioned as designed, with control lines securely fastened throughout the operation and an average installation time of around 50 seconds per joint.
The ACLC concept was initiated in 2020 at the request of Equinor to improve completion operations by integrating automation. Ace Well Technology partnered with Expro to develop the system, combining Ace’s expertise in mechanical downhole solutions with Expro’s remote handling technology. The collaboration culminated in this successful deployment, demonstrating both the technical capabilities and operational efficiency of the system.
The achievement represents a significant step in the evolution of well completion processes, showcasing how automation can streamline installation tasks while maintaining reliability and precision. Interested readers can watch a video demonstration of the RCIS system on YouTube to see the operation in action.
This first deployment of the ACLC with RCIS underlines the growing role of technology-driven solutions in the oil and gas sector, illustrating how engineering innovation can enhance performance, consistency, and operational excellence on the Norwegian Continental Shelf.
Global energy technology company SLB has announced that its OneSubsea joint venture has secured an engineering, procurement, and construction (EPC) contract from Equinor for a 12-well, all-electric Subsea Production System (SPS) in the Fram Sør field, located offshore Norway.
The contract follows a year-long collaborative Front-End Engineering Design phase during which Equinor and SLB OneSubsea jointly advanced the project. This collaboration resulted in the finalized development plan and final investment decision (FID). Under the EPC scope, SLB OneSubsea will provide four subsea templates and 12 all-electric subsea trees. This eliminates the need for hydraulic fluid supplied from the host platform and minimizes topside modifications, offering a cost-efficient solution while preserving topside capacity for potential future developments in the area.
"Fram Sør is a breakthrough project for our industry, marking the first large-scale all-electric subsea production system," said Mads Hjelmeland, chief executive officer of SLB OneSubsea. "Not only do all-electric subsea solutions significantly reduce topside needs to make large-scale tiebacks such as the Fram Sør development possible, but they also hold the key to unlock more marginal resources through their reduced footprint and simplified operations."
The development will be executed as a subsea tieback to the Troll C host platform in the North Sea, enhancing energy supply security from the Norwegian continental shelf (NCS) to Europe. Since the host platform is powered from the Norwegian mainland, production from Fram Sør will have very low emissions.
The contract remains subject to regulatory approval of the plan for development and operations (PDO).
Subsea7 has secured a major contract with Turkish Petroleum Offshore Technology Centre (TP-OTC) for the development of Phase 3 of the Sakarya field development in the Black Sea.
Subsea7’s scope includes engineering, procurement, construction and installation (EPCI) of the subsea umbilicals, risers and flowlines. Progress will begin immediately and will be managed by the Subsea7 office in Istanbul.
David Bertin, Senior Vice President for Subsea7 Global Projects Centre East, said, “This awards builds on our track record in Türkiye and further reinforces our relationship with TP-OTC, demonstrating Subsea7’s expertise in delivering complex, integrated offshore projects safely and reliably. It underlines our commitment to supporting Türkiye’s strategic energy goals and advancing our strong regional presence.”
Hulya Ozgur, Subsea7’s Türkiye Business Unit Director, commented, “We are proud to continue our journey with TP-OTC on the Sakarya Gas Field Development Project, supporting Türkiye’s vision for energy independence. This new award reflects the dedication and capability of our Türkiye team, our commitment to local content development, and our focus on delivering safe and efficient offshore solutions.”
Autonomous subsea software company, Nauticus Robotics, has announced the Aquanaut Mark 2 has set a new record for ultra-deepwater depth off the coast of Louisiana.
The flagship fully electric-operated underwater vehicle reached depths of 2,300 metres underwater, opening new opportunities for underwater monitoring.
Daniel Dehart, Nauticus’ VP of Field Operations, said, “I am pleased to report our vehicle has reached unprecedented ultra-deepwater depths without the need of a tether. Reaching this new depth is an exciting milestone, and we have obtained significant data on both Aquanaut and ToolKITT from these tests – particularly regarding acoustic communication challenges in ultra-deepwater.
“Our Autonomous Solutions team will spend the necessary time to analyse the new data and apply this information to optimise performance for our ultra-deep applications and across our portfolio.”
CEO John Gibson commented, “The more time we spend untethered in the water, the greater our operational and technical lead expands in the market. I want to thank our employees for their dedication to innovating for our customers and their offshore projects. I’m proud that our team is constantly finding solutions to strengthen our capabilities underwater and enhance revenue opportunities for projects at these depths.”
Recent events in Australia’s decommissioning space demonstrate the complexity of offshore decommissioning campaigns from the environmental and work, health and safety perspectives.
Lessons learned from these experiences will assist the industry to prepare itself to meet the large influx of decommissioning work ahead, according to a new insight paper from law experts at Pinsent Masons, co-authored by Cormac Mercer and Laura Slocombe, which continues below:
Last week, the Wilderness Society commenced proceedings against the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) in the Federal Court seeking judicial review over its approval of an environmental plan (EP) from Santos WA Northwest Pty Ltd (Santos) for its Reindeer wellhead platform to be “left in a preserved state for future phases”. This is despite Santos’ Reindeer field having ceased production this year.
Offshore activities, including decommissioning, must be approved by NOPSEMA. The approval process involves lodging certain documents, including an EP, along with an operation management plan and a safety case. The EP is generally the most significant, and potentially problematic, of these.
The Wilderness Society has publicly claimed that, by approving Santos’ EP, NOPSEMA did not enforce Santos’ duty under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (OPGGS Act) as titleholder of the Reindeer facilities to maintain financial assurance, in particular in relation to decommissioning the infrastructure and remediating damage to the surrounding environment.
Section 571(2) of the OPGGS Act requires a titleholder to maintain financial assurance sufficient to give the titleholder the capacity to meet costs, expenses and liabilities arising in connection with, or as a result of:
the carrying out of the petroleum activity;
the doing of any other thing for the purposes of the petroleum activity; or
complying, or failing to comply, with a requirement under the OPGGS Act in relation to the petroleum activity.
The duty imposed by section 571(2) of the OPGGS Act extends to covering any costs, expenses or liabilities arising in connection with, or because of, compliance with a titleholder’s duty under section 572C of the OPGGS Act, which relates to the escape of petroleum.
If NOPSEMA’s decision to approve Santos’ EP is ultimately quashed by the Federal Court, it could result in NOPSEMA assessing EPs in the future on the basis of demonstrated financial capacity to undertake decommissioning. The Wilderness Society matter is now before the Federal Court.
This litigation contributes to the recent rise in legal challenges to NOPSEMA’s EP approvals. Whether this leads to a more conservative approach to decommissioning activities by titleholders and NOPSEMA, potentially disincentivising developers from exploring innovative decommissioning solutions with positive environmental outcomes, remains to be seen.
Environmental approvals for major offshore decommissioning projects will continue to be under increased scrutiny, adding to the complexity of offshore decommissioning campaigns. Businesses operating in the offshore space should ensure that EPs and assessments, including consultation, are undertaken in a comprehensive manner with a close eye on recent legal and scientific developments.
Work, health and safety
In general, offshore decommissioning is an inherently hazardous process that exposes workers to a variety of physical and psychosocial risks.
Infrastructure requiring decommissioning is often located in harsh and unpredictable marine environments which are geographically isolated. Remote work has become a well-known psychosocial hazard in many industries but is particularly acute in the renewable energy industry, due to minimal access to resources and support, often for prolonged periods of time.
In addition, other obvious physical hazards include the handling of hazardous chemicals and contaminants; manual handling challenges in bringing infrastructure to shore; fires and explosions; and interactions with people and mobile plant, including sea vessels.
NOPSEMA is paying close attention to offshore decommissioning works in Australian waters and is cracking down on operators who are failing to mitigate risks.
Recently, NOPSEMA issued three general directions to Woodside for its Stybarrow and Griffin fields off the Western Australian coast and Minerva field offshore of Victoria.
Each direction requires Woodside to undertake and document a risk assessment to identify and evaluate all risks to health, safety and the environment associated with Woodside’s removal activities. This includes a requirement that “control measures” are in place to reduce risks to as low as reasonably practicable. NOPSEMA’s intervention comes off the back of an oil spill incident at Woodside’s Griffin field. In addition to potential environmental damage, there were concerns that workers were exposed to hydrogen sulphide, an extremely toxic gas, due to the spill.NOPSEMA has powers to enforce WHS compliance on offshore projects that reflect the powers of state, territory and Commonwealth regulators under the model harmonised work health and safety laws. For example, inspectors can:
enter offshore facilities to conduct inspections and interviews;
issue provisional improvement notices, prohibition notices and infringement notices; and
take possession of plant and samples.
NOPSEMA can also commence criminal and civil prosecutions, seek injunctions - stopping someone doing a certain action or activity - and apply for adverse publicity orders against corporate entities, with reputational impacts.
Operators of decommissioning projects in Australian offshore environments are reminded that they must take all reasonably practicable steps to protect the health and safety of workers at the facility and of any other persons who may be affected by their activities. This is a legislative obligation prescribed by the OPGGS Act, largely mirroring the primary duty under the harmonised work health and safety framework that requires a person conducting a business or undertaking to ensure, so far as is reasonably practicable, the health and safety of workers and others.
If risks cannot be fully eliminated, which is usually the case in high-risk workplaces such as offshore decommissioning facilities, operators should not wave the white flag and sit still. They have a duty to ensure that all risks are minimised, so far as is reasonably practicable, particularly those which are known, obvious and foreseeable.
Halliburton has announced the launch of SK Well Pages, a new addition to its Summit Knowledge (SK) digital ecosystem, aimed at transforming how electric submersible pump (ESP) operations are managed.
This integrated platform enhances decision-making and production optimisation through the use of AI, machine learning, and advanced data analytics.
Part of Halliburton’s wider strategy to digitise oilfield operations, SK Well Pages provides a unified workspace tailored for ESP and HPS (horizontal pump systems) operations. It consolidates engineering, manufacturing, and real-time operational data to offer a complete, up-to-date view of performance. The platform also introduces automated workflows, improving both quality control and operational efficiency.
Designed with usability in mind, SK Well Pages includes customisable dashboards that offer clear visualisations of pump performance, surface sensors, and production trends. This enables proactive real-time monitoring and supports faster, more informed decision-making.
The platform is fully integrated with Halliburton’s advanced digital tools, including SpyGlass, for accurate pump sizing, and the Intelevate platform, which provides remote monitoring and control. Intelligent alerts, predictive models, and trend analysis help reduce downtime and extend equipment lifespan.
Greg Schneider, vice president, Artificial Lift, Halliburton, said, “We provide customers with advanced digital tools that give them clarity and control to make confident decisions. The Summit Knowledge digital ecosystem with SK Well Pages is a powerful step forward in the journey of how we deliver digital innovation for superior ESP optimisation.”
With SK Well Pages, Halliburton continues to drive innovation in artificial lift technology, offering oilfield operators a smarter, more connected way to optimise production.
Helix Energy Solutions has been awarded a multi-year contract for production enhancement and well abandonment services in the Gulf of America with an undisclosed major operator.
The contract will commence next year and calls for the provision of either the Q5000 or Q4000 riser-based well intervention vessel, a 10k or 15k Intervention Riser System (IRS) and remotely operated vehicles.
Helix’s services will cover operations from fully integrated production enhancement to full integrated plug and abandonment well services.
Scotty Sparks, Executive Vice President and Chief Operating Officer, said, “We are pleased to expand our backlog by successfully executing another multi-year contract for well intervention services. This contract underscores our commitment to delivering safe, cost-effective and efficient production enhancement and abandonment services in the Gulf of America, supported by Helix’s advanced vessels, decades of industry-leading experiences, and the collaborative capabilities of our Subsea Services Alliance.”
The contract includes equipment and services as part of the Subsea Services Alliance: a strategic partnership between Helix and SLB.
The decommissioning challenge is coming into sharp focus for Asia Pacific, as it is across much of the globe — but this brings with it immense opportunity too.
Offshore platform decommissioning can bring with it clean energy and resort development initiatives, artificial reefs and sustainable energy transition opportunities if thoroughly planned and well executed.
That’s one of the core messages from a new insight paper by top law firm Norton Rose Fulbright which assesses the decommissioning challenge facing Asia and elsewhere.
Since 1950, it estimates that over 12,000 offshore oil and gas platforms have been installed globally.
It is forecast that 2,600 may require decommissioning by 2040 at a cost of approximately US$210bn.
Newer platforms sited in deeper waters face higher decommissioning costs — but there are also opportunities, according to Norton Rose Fulbright.
“Southeast Asia, Indonesia and Malaysia have some of the most challenging offshore platform decommissioning obligations globally,” it notes.
“In addition to the significant magnitude of these obligations, uncertainty resulting from unpredictable allocation of decommissioning financial responsibility can impede international investors’ efforts to divest assets and undermine investor confidence in new projects.”
Asia reportedly hosts over 1,750 offshore oil and gas assets, with 85% sited in Indonesia and Malaysia, most operating for 20 years or longer.
Approximately 200 offshore fields are expected to cease production in southeast Asia by 2030, with projected decommissioning costs of roughly US$100bn.
Greater clarity in relation to decommissioning regimes is therefore urgently needed, the law firm notes.
“The issue is especially acute in Indonesia, where production-sharing contracts governing many concessions will soon expire. Operators or investors may view the government or national oil companies (NOC) as responsible for decommissioning costs, while government parties may assert the operator should take responsibility. Indonesia has a decommissioning legal framework, but relevant requirements are not yet fully clarified.”
Malaysia could provide something of a solution.“Malaysia has a history of artificial reef construction, independent of offshore platform decommissioning, with Malaysia’s government and NOC, Petronas, having expressed support for RTR (Rigs-to-Reefs),” the insight paper states.
“Malaysia’s Baram-8 decommissioning was the first RTR project in the South China Sea and was successful.”
Malaysia is also exploring alternative and innovative decommissioning concepts including recreational use of decommissioned platforms, the paper adds.
The RTR debate ensues globally, the law firm notes, and work remains to evaluate RTR’s future prospects, while the issues of costs and liability allocation require attention.
“Marine organisms reportedly provide 50% of our oxygen, while oceans produce 15% of our protein and absorb about 40% of global CO2 emissions. But some stakeholders believe increasing CO2 levels may cause increasing ocean acidification, accelerating loss of natural coral reefs and marine habitat.
“Thus, in addition to preserving and enhancing marine fisheries’ habitat and food resources, broader adoption of RTR decommissioning holds the potential to counteract the global loss of natural coral reefs and, thereby, to help preserve and enhance the marine ecosystem’s capacity to continue providing CO2 absorption and oxygen production capacity, critical to sustaining our world.”
Kent, the global integrated energy services partner is acquiring Exceed (XCD) Holdings Limited, to create a global leader in decommissioning, well management and sub surface engineering services.
This acquisition will strengthen Kent’s position in the fast-growing global decommissioning market, set to rise from US$8bn to US$16bn a year by 2035, as the company aims to become a full-service partner across the energy lifecycle, including late-life operations through to the safe and successful decommissioning of customer assets.
Exceed, headquartered in Aberdeen and active in over 40 countries, has two decades of experience in delivering complex offshore well projects, with over 70 wells drilled and more than 150 decommissioned to date. Its proven delivery model and track record will combine with Kent’s global platform and project execution strength to meet growing demand for safe, compliant and cost-effective end-of-life solutions for oil and gas infrastructure.
The deal could also open up significant energy transition opportunities given Exceed is already repurposing reservoirs for carbon capture and hydrogen storage projects, and Kent also has expertise in this area.
“Our agreement to acquire Exceed is a bold step into the future of responsible energy operations,” said John Gilley, CEO of Kent. “Exceed’s specialist capabilities in well and reservoir management, coupled with their strong reputation in decommissioning, complement our vision of offering full lifecycle services to our clients. Together, we will be uniquely positioned to help the industry navigate energy security, net-zero mandates, and the safe retirement of offshore assets.”
Ian Mills, Managing Director of Exceed, commented, “We’ve built Exceed over 20 years with a commitment to technical excellence, innovation and client trust. Joining forces with Kent is the natural next step. It gives us the financial backing and global reach to scale our expertise to new markets and opportunities, while preserving the same culture, entrepreneurial spirit and values that define us.”
The transaction is expected to be completed later this year.
Jadestone Energy plc has provided an update on the testing and production performance of the Skua-11ST well at the Montara field, located offshore Australia.
Production from the Skua-11ST well began in early August 2025 and has exceeded expectations. Initial oil production rates surpassed 6,000 barrels per day (bbls/d), well above the earlier guidance of 3,500 bbls/d. Following this initial surge, production rates stabilised at around 4,400 bbls/d with the well operating on a 40% open choke, before other subsea wells at the Montara field were restarted.
The Skua-11ST well was equipped with downhole inflow control devices. These are designed to optimise the sweep and recovery of the reservoir, helping to maximise oil extraction. Moving forward, Skua-11ST and the other wells at Montara will be managed carefully to ensure the highest possible recovery from the field over the longer term.
Commenting on the results, T. Mitch Little, Chief Executive Officer of Jadestone, said, “We are pleased to report the strong initial flows from the Skua-11ST well, which will meaningfully contribute to higher production from Montara, underpinning our revised 2025 production guidance which was upgraded in July. The increase in production will also reduce Montara unit operating costs and extend field life by approximately one year.”
These encouraging results mark a significant step for Jadestone Energy, supporting both improved production forecasts and the long-term sustainability of the Montara field’s operations.
Following the release of a new study exploring the infrastructure and capabilities required to support offshore oil and gas decommissioning in the Northern Territory, a timetable of potential projects and opportunities is coming into focus.
It begins with subsea infrastructure and mooring systems associated with the Northern Endeavour project, coming ashore from 2025, and continues through the decades culminating with potential involvement on Ichthys, coming ashore from 2058 onwards.
However, the intermittent nature of the work means the establishment of a permanent, local decommissioning and abandonment (D&A) workforce is unlikely to be economic, compared with resources and labour at rival locations, notably Western Australia (WA).
Australia's Centre of Decommissioning (CODA) released its Northern Territory report in July highlighting some of the limitations of the region, as well as areas in which it can play a meaningful role in the nation’s decommissioning efforts.
“It is not deemed credible for large fixed facilities (i.e., non-wellhead platforms) or floating facilities to be decommissioned in the Northern Territory,” the report notes.
However, the state does appear to hold a great deal of promise in aiding work to process related subsea infrastructure and mooring systems.
From a planning perspective, CODA states, the following are the most credible oil and gas decommissioning opportunities in the Northern Territory:
2025: Subsea infrastructure and mooring systems associated with the Northern Endeavour, coming ashore from 2025.
2032-2036: Subsea infrastructure, mooring systems and a wellhead platform associated with Montara, coming ashore between 2032 and 2036.
2038: Subsea infrastructure, mooring systems (CALM buoy) and a wellhead platform associated with Blacktip, coming ashore from 2038.
2047-2052: Subsea infrastructure and mooring systems associated with the Prelude and Crux developments, coming ashore between 2047 and 2052.
2050-2055: Subsea infrastructure, mooring systems and a wellhead platform associated with the Barossa and possibly the Bayu Undan developments, coming ashore between 2050 and 2055.
2058-2063: Subsea infrastructure and mooring systems associated with Ichthys, coming ashore from 2058 and 2063.
Crucially, the report suggests that based on the estimated decommissioning dates, there does not appear to be significant overlaps in the decommissioning windows of the various developments.
Lack of overlap means that each decommissioning campaign will need to be established separately – including leases on land, and mobilisation of a workforce and equipment.
“Between the defence and offshore oil and gas industries, there is unlikely to be the demand to sustain a continuous decommissioning workforce especially compared with other jurisdictions such as WA,” it notes.
“Given decommissioning requires specialist capability, this will result in a short-term or ‘project’ based workforce,” it adds.
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