Two exploration wells on Block 2914 that fall under the purview of Petroleum Exploration License (PEL) 85 offshore Namibia have now been delivered by Rhino Resources and Halliburton.
Orchestrated from Halliburton's new operational bases in Walvis Bay, Swakopmund and Luderitz, the operation was made possible with world-class technology and local collaboration.
Antoine Berel, vice president, Halliburton sub-Saharan Africa, said, "This success is an example of what’s possible when world-class technology, local collaboration, and a shared long-term vision come together. Our newly established infrastructure across Namibia enabled this discovery, which will help unlock Namibia’s energy potential and build the capacity to support the country’s future as an energy hub in Africa."
As Namibia attracts international interest in its offshore basins, the success of this campaign sets a new standard for energy development in the region.
“At the onset of the drilling campaign, we communicated to our partners that Rhino’s exploration efforts in Namibia should simultaneously prove geological potential and deliver long-term benefits for the country. The discoveries on Block 2914 are a promising start to this journey, which will contribute to the foundation we are laying for Namibia’s burgeoning oil and gas industry — one built on knowledge and skills transfer, local capacity building and the upliftment of young Namibians,” said Travis Smithard, CEO of Rhino Resources.
The Rhino-Halliburton Technology Centre at the University of Namibia (UNAM) Southern Campus came into being in October last year to advance geoscience education and research nationwide.
Europe’s well intervention market is poised for steady growth in 2025, supported by advances in digital platforms, subsea integrity projects, and integrated well management services.
Operators and service providers across the North Sea and other mature European basins are adopting innovative technologies to improve well performance, reduce downtime, and extend asset life, which are critical factors as many fields transition from peak production to late-life operations.
A key development is Sentinel Subsea’s completion of a major North Sea integrity project. This initiative focused on enhancing subsea infrastructure reliability through advanced inspection, maintenance, and repair techniques. The project highlights how subsea integrity management is becoming a cornerstone of well intervention strategies, helping operators mitigate risks and optimize production in complex environments.
Meanwhile, Schlumberger (SLB) is advancing well intervention through its newest digital platform, Electris. The technology leverages real-time data analytics, machine learning, and remote monitoring capabilities to provide operators with deeper insights into well conditions. This enables predictive maintenance and faster decision-making, reducing intervention costs and improving uptime.
Exceed, a specialist well management company, is also playing a vital role by delivering integrated well management services for Viaro’s assets in the North Sea. Their approach combines detailed well planning, intervention execution, and data-driven optimisation, reflecting the broader market trend towards end-to-end well lifecycle management. This helps operators adapt to evolving reservoir conditions and maximize economic recovery.
According to the “Europe Well Intervention Market, By Country, Competition, Forecast and Opportunities, 2020-2030F” report conducted by Research and Markets, the sector is expected to grow from US$4.73bn in 2024 to US$7.17bn by 2030.
The European well intervention market itself shows promising prospects. Driven by the need to maintain production from ageing fields and the increasing complexity of reservoir conditions, operators are expected to invest steadily in both traditional and innovative intervention techniques. Services such as coiled tubing, wireline, and subsea intervention are evolving to meet these demands with improved efficiency and safety standards.
Moreover, digitalisation and automation continue to transform the sector. Operators seek to reduce operational risks and carbon footprints while optimising costs, aligning with Europe’s energy transition goals. Emerging technologies, including digital twins, AI-powered diagnostics, and advanced robotics, are being piloted and gradually integrated into intervention workflows.
In summary, 2025 is set to be a pivotal year for Europe’s well intervention market, where technological innovation and integrated service models will drive growth, improve asset integrity, and support sustainable hydrocarbon production amid a changing energy landscape.
United Arab Emirates' industral base, ADNOC, has signed a strategic partnership agreement with advanced tubular solutions provider, Tubacex, to localise critical oilfield technology.
This will ensure cost reduction and supply chain resilience for ADNOC as it leverages Tubacex’s Sentinel Prime premium tubular joint connection technology for well completion operations.
Also defined as oil country tubular goods (OCTG), tubulars are steel pipes specially made for drilling and completion activities. These components must meet stringent standards for strength, durability and reliability to operate in high-pressure, high-temperature environments deep underground.
A dedicated research and development (R&D) centre will be established as a hub for advanced engineering by Tubacex in Abu Dhabi. It will advance local content by training highly skilled technicians in-country.
Musabbeh Al Kaabi, ADNOC Upstream CEO, said, "This strategic partnership secures ADNOC access to an important technology for completing oil and gas wells, reinforcing our role as a reliable global energy provider and our efforts to boost domestic manufacturing capacity. We welcome Tubacex’s investment in a new research and development center in Abu Dhabi which will enable knowledge and technology transfer, help develop local talent and support the goals of the Make it in the Emirates initiative.”
Josu Imaz, Tubacex Group CEO, said: “The licensing arrangement with ADNOC confirms Tubacex’s commitment to innovation and excellence in the energy sector and reinforces our position as a strategic contributor for major players in the industry.”
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The Department of the Interior has announced that the lead federal agency responsible for overseeing decommissioning activities within the Chumash Heritage National Marine Sanctuary will be the Bureau of Safety and Environmental Enforcement (BSEE).
The responsibility was transferred from the Department of Commerce to the Interior, underscoring the critical role BSEE plays in managing safe and environmentally sound offshore transitions.
The transfer followed extensive coordination between the National Oceanic and Atmospheric Administration, BSEE and the Bureau of Ocean Energy Management, ensuring a unified approach to decommissioning in the Sanctuary.
Acting Assistant Secretary for Land and Minerals Management, Adam Suess, said, “This is a strong example of interagency collaboration to streamline permitting and promote responsible energy development while honouring our commitment to environmental protection. By leveraging BSEE’s regulatory expertise, we can ensure that offshore decommissioning activities within the Sanctuary are conducted safely and efficiently.”
BSEE Principal Deputy Director, Kenneth Stevens, commented, “The announcement exemplifies our commitment to streamlining processes, reducing unnecessary regulatory burdens, and promoting energy production in alignment with strong environmental protections. Early coordination between NOAA and BSEE will ensure clarity and efficiency, establishing agreed-upon mitigation measures and providing a streamlined regulatory pathway for permittees.”
Boasting an operational capacity of 180,000 barrels of oil, the floating production storage and offloading facility (FPSO) Alexandre de Gusmao has begun production activities for Shell Brasil in the Mero field in the Santos Basin offshore Brazil.
Its exceptional oil production capacities besides, the FPSO will also be able to generate 12 mn cu/m of gas compression per day (Shell share 19.3%) following its connection to 12 wells as part of the Mero-4 project.
The FPSO is located 180 kilometres from the coast of Rio de Janeiro in a water depth of approximately 2,000 metres.
“Mero-4 is the latest example of how we are working with our partners to unlock value from world-class reservoirs, sustaining material liquids production and providing for the world’s current energy needs,” said Peter Costello, Shell’s Upstream President. “Our Brazil portfolio features long-life assets with high flow rates, resulting in some of our most competitive barrels on both operating cost and carbon footprint.”
The unitised Mero field is operated by Petrobras (38.6%), in partnership with Shell Brasil (19.3%), TotalEnergies (19.3%), CNPC (9.65%), CNOOC (9.65%) and Pre-Sal Petroleo SA (PPSA) (3.5%) representing the Government in the non-contracted area.
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Decommissioning Australia’s ageing oil infrastructure will not only be a test of the industry’s technical and engineering prowess – increasingly, it will also challenge its economics.
With the slump in oil prices undermining the finances of the major oil and gas companies in recent months, operators will need to work harder and smarter to meet stringent decommissioning objectives in the face of tighter spending constraints.
Oil prices have drifted downwards for the most part this year, at times below US$60 per barrel, squeezing budgets across the board.
Max Oppenheimer, Client Advocate - Energy at Miller Insurance, said this will test decommissioning activities across all major oil and gas production basins in the world.
Potentially, it could also trigger an acceleration in decommissioning work as operators seek to retire ageing, underperforming assets.
“Previous slumps in the oil price in 2014, and during the 2020 onset of Covid-19, impacted project economics and saw periods of accelerated decommissioning activity as operator’s sought to cold stack ageing assets to mitigate their losses,” Oppenheimer noted in a 9th May 2025 briefing posted on the company’s website.
“Prices are currently testing post-Covid lows, and risk managers may once again be faced with addressing decommissioning risk concerns sooner and on accelerated timescales.”
From an insurance perspective, Oppenheimer also outlined a range of claims scenarios that could arise from decommissioning activities and that should be considered by operators, as well as risk managers.
Australia may, however, be able to learn lessons from other major producing regions across the globe, he added, notably mature basins such as the North Sea.
“Decommissioning is a global challenge to the energy industry,” said Oppenheimer. “The greatest obligations currently reside in the North Sea basin, followed by Brazil and the USA.”
In the North Sea, a total of 22 fields ceased production during 2024, and up to 40% of currently producing fields could cease production by 2030 based upon current investment plans, or sooner if investment cases falter based on a lower crude outlook.
At the end of 2024, a backlog of 483 wells in the UK sector alone required plugging and abandonment activities, a number that could double to 2030.
“The UK challenge is particularly acute,” said Oppenheimer, “with annual decommissioning spend set to average in excess of US$3bn in the mid-term outlook.”
Australia recently agreed to work more closely with the UK in the area of decommissioning as the task becomes more pressing.
Global Underwater Hub (GUH) and Subsea Innovation Cluster Australia (SICA) signed a Memorandum of Understanding (MoU) in April to collaborate in the subsea sector, with a focus on areas such as decommissioning, as well as carbon capture.
At the time of the announcement, GUH Chief Executive, Neil Gordon, said decommissioning represented a “significant opportunity” in Australia, where the inventory of subsea assets to be decommissioned includes over 1,500 wells and structures and 4,500km of pipelines.
This would stimulate “major opportunities” for specialist plugging, cutting, inspection and recovery technologies, he noted.
Viaro Group has appointed well management company, Exceed Energy, as the well operator for the 192 wells from One Gas West assets.
This follows Viaro’s acquisition of the North Sea assets from Shell and ExxonMobil.
The contract will enable Exceed to manage all aspects of late life well operations, starting with the decommissioning of the 26 wells associated with the SNS Leman Foxtrot and Golf platforms, which commences later this year.
This will be followed by well intervention and further decommissioning operations, as well as the development of new gas production wells as per the five-year, multi-million contract.
Marking the win as the most significant in its 20-year history, John Anderson, Exceed's Commercial Director – Wells, said, "Our well and reservoir management capabilities have gained an outstanding reputation for the ability to balance decarbonisation with energy security and affordability, as we continue to champion a sustainable UK energy transition.
"Understandably, this contract has been keenly contested across the North Sea industry, and we are delighted that our capacity and competency have been recognised by Viaro as providing optimum levels of expertise and support for its major acquisition."
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The Abu Dhabi National Oil Company (ADNOC), the UAE’s largest offshore oil and gas producer, is revolutionising its offshore operations by prioritising locally-manufactured products, aligning with the “Make it in the Emirates” initiative.
ADNOC produces 4.85 barrels of oil per day, accounting for half of Abu Dhabi’s oil production capacity. This includes its nine offshore fields.
The company's push for local sourcing enhances efficiency, reduces supply chain risks, and supports the UAE’s economic diversification, as highlighted at the 2025 Make it in the Emirates forum (MIITE), which took place from 19-22 May this year.
ADNOC Logistics & Services (ADNOC L&S) is leading this transformation, deploying UAE-built offshore support vessels (OSVs) equipped with smart digital systems for real-time monitoring.
At MIITE, Capt. Mohamed Al Ali, SVP Offshore Logistics, emphasised these vessels’ role in optimising logistics for offshore fields, showcasing Emirati expertise and the role ADNOC is playing in enhancing Emiratisation.
In 2024, ADNOC L&S also acquired six flat-top cargo barges from Dubai’s Premier Marine Engineering, supporting its engineering, procurement, and construction (EPC) projects.
On the other hand, ADNOC’s partnership with Tubacex, announced on 19 May, introduces locally-developed well completion technologies at a new UAE R&D centre.
These AI-driven systems enhance subsea interventions like wireline logging and stimulation in fields such as Lower Zakum, boosting recovery rates.
Additionally, ADNOC has awarded AED543 million (US$147.8mn) in contracts to nine local suppliers for products like valves and corrosion inhibitors, which are critical for offshore well integrity.
These agreements, facilitated by ADNOC’s In-Country Value (ICV) programme, aim to localise AED90 billion (US$24.5bn) in procurement by 2030, creating 3,500 skilled jobs.
The RoboWell AI system, deployed across 10 wells at the NASR field in 2024, marks a global first for autonomous offshore well control.
Developed with AIQ, RoboWell uses cloud-based algorithms to optimise operations, reducing emissions and human supervision. Plans to expand to 300 wells underscore ADNOC’s digital leadership.
Critically, while local manufacturing strengthens resilience, reliance on foreign partners like Tubacex for advanced tech highlights a need for deeper UAE innovation.
ADNOC’s strategy, blending local production with global expertise, positions it as a pioneer in sustainable offshore operations, driving UAE’s industrial growth.
In 2025, the offshore oil and gas sector in the Gulf of America is undergoing a rapid transformation, as new well intervention technologies reshape how operators approach subsea production, integrity, and high-pressure challenges.
With legacy fields maturing and operational efficiency becoming a strategic priority, companies are turning to advanced systems and partnerships to optimise well performance, extend asset life, and reduce rig time.
Chevron’s Ballymore development stands out as a symbol of this shift. By leveraging a subsea tieback to the existing Blind Faith platform, the project avoids the need for new topside infrastructure while still enabling high-yield production from three wells. This infrastructure-light approach exemplifies a broader industry trend, as operators seek scalable, sustainable solutions that reduce capital expenditure while accelerating timelines. Ballymore is expected to contribute significantly toward Chevron’s target of producing 300,000 barrels of oil equivalent per day from the region by 2026.
On the other hand, Shell is deploying innovative materials in its Whale project, located around 200 miles offshore. The company has partnered with CRP Subsea to introduce crushable foam wrap (CFW) technology – engineered to collapse under specific temperature and pressure thresholds. This provides thermal expansion management and pressure relief in the annulus, addressing critical integrity challenges in deepwater completions. Set for phased delivery starting in the third quarter of 2025, the technology reflects growing emphasis on preemptive integrity control in complex environments.
Meanwhile, intervention hardware is also evolving to meet the region’s high-pressure demands. Trendsetter Engineering has successfully deployed its Trident 20K system at Beacon Offshore’s Shenandoah project. Designed for operations in ultra-high-pressure wells, the intervention system was installed from the Deepwater Atlas drillship and enabled a two-well flowback campaign without requiring the system to be recovered between wells. Its modular design and wet-mate capabilities allowed operators to save valuable rig time while maintaining safety in technically challenging conditions.
The Gulf of America is shifting toward a model where reliability, modularity, and pressure management dominate offshore engineering priorities. As Chevron retools infrastructure usage, Shell integrates intelligent thermal solutions, and Trendsetter pushes the limits of high-pressure intervention, the region is positioning itself as a proving ground for next-gen well intervention technologies. These advancements are expected to support longer well life cycles and safer operations as operators balance performance with cost control.
The European well intervention market, valued at US$4.73bn in 2024, is forecasted to grow to US$ 7.17bn by 2030, at a CAGR of 7.02%. Well intervention encompasses a range of operations aimed at maintaining, repairing, or boosting oil and gas wells to ensure optimal production and efficiency.
Demand in Europe is rising due to energy security concerns amid geopolitical tensions and supply disruptions. To reduce reliance on imports, European countries are investing heavily in well intervention services to maximise output from existing assets. Techniques such as enhanced oil recovery (EOR) and gas lift optimisation play vital roles in sustaining production levels and managing decline rates. Operators are also balancing fossil fuel production with sustainability objectives, using well intervention to lower environmental impact.
Despite its growth, the market faces challenges including high operational costs, especially offshore in regions like the North Sea, where harsh conditions and complex logistics increase expenses. Price volatility in the oil and gas sector, along with rising material costs and supply chain issues, add further pressure.
To address these hurdles, the industry is adopting cost-effective methods like rigless interventions, leveraging advancements in coiled tubing and electric wireline technologies. Maintaining stringent safety standards remains a priority.
Digital transformation is reshaping the sector through AI, machine learning, and real-time data analytics, which help optimise operations, cut costs, and improve safety. Technologies such as fiber-optic sensors and downhole cameras support remote monitoring and predictive maintenance, reducing downtime and preventing failures.
Robotic intervention systems and remotely operated vehicles (ROVs) are increasingly used to improve safety and efficiency in hazardous offshore environments. Autonomous coiled tubing units and electric wireline tools enable precise, minimally disruptive interventions.
The market covers service types, well types, and applications across countries like Norway, the UK, Turkey, Italy, Denmark, and Germany. Comprehensive competitive analyses highlight major players and emerging opportunities tailored to corporate strategies.
This analysis is based on the report “Europe Well Intervention Market, By Country, Competition, Forecast and Opportunities, 2020-2030F” conducted by Research and Markets. For more information, visit here
In a significant stride for India’s energy infrastructure, the Panna-Mukta and Tapti (PMT) joint venture – comprising Shell (via BGEPIL), Reliance Industries Limited (RIL), and ONGC – has wrapped up country’s first offshore decommissioning project successfully.
The milestone marks the safe removal of offshore facilities in the mid and south Tapti fields, located off India’s west coast.
The PMT JV, which operated the Tapti fields under a production sharing contract with the Government of India, includes ONGC with a 40% stake, and BGEPIL (Shell) and Reliance holding 30% each.
Production from the fields ceased in March 2016, marking a major shift in India’s oil and gas sector – from extracting resources to safely shutting down operations.
The multi-phase project involved the removal of five wellhead platforms, the safe plugging and abandonment of 38 wells, and the removal of infield pipelines. The entire process closely adhered to safety and environmental standards, at every stage – from offshore execution to onshore dismantling, planned with utmost precision.
The project, aligned with India’s ‘Make in India’ mission, awarded major contracts to Indian firms – Larsen & Toubro, who led the offshore removal, while Chowgule Shipyard in Ratnagiri handled the onshore dismantling. This not only strengthened domestic capability in energy infrastructure but also created a blueprint for future decommissioning operations in Indian waters.
What sets this project apart is not just its scale but its role in shaping a strong regulatory and operational framework for offshore decommissioning in India. Built in close collaboration with stakeholders – the Ministry of Petroleum and Natural Gas, the Directorate General of Hydrocarbons, and the Oil Industry Safety Directorate, the Tapti decommissioning project sets a benchmark of how legacy fields can be responsibly retired.
“The safe and successful completion of the Tapti offshore project is a landmark moment for India’s offshore energy sector,” said Nipun Pradhan, managing director of BGEPIL and GM, Shell Upstream India, adding, that this project sets a new benchmark for responsible decommissioning, which has been made possible by global expertise, strong collaboration, and an unwavering commitment to safety and sustainability.
Sanjay Barman Roy, president of E&P, Reliance Industries, shared, “The safe and responsible offshore decommissioning by the PMT JV marks a significant step forward for India’s energy sector. From the outset, the JV partners worked tirelessly to strengthen local supply chains and enhance the technical and safety capabilities of Indian contractors, especially for offshore dismantling activities,” stating that this has been successful in fulfilling the government’s ‘Make and Break in India’ vision.
For ONGC, the project’s complexity, given its proximity to active assets, underscored the importance of meticulous planning. “This first-of-its-kind large-scale offshore decommissioning underscores ONGC’s commitment to responsible energy practices, said Pankaj Kumar, director of production, ONGC, expressing that the project’s complexity, especially its proximity to ONGC’s live assets demanded strategic planning, precise execution, and utmost focus on safety and that it sets the foundation for India’s next chapter in offshore transformation.
As India strives to balance energy growth with environmental responsibility, the Tapti project sets a timely benchmark for offshore decommissioning in the country’s evolving energy transition.
Offshore contractor Allseas — which has been tasked with decommissioning work in the Bass Strait for ExxonMobil Australia — is expanding its fleet.
Its new cargo barge, Braveheart, which is being added to the fleet to boost flexibility for heavy lift campaigns, is now taking shape at the CIMC Changhong Shipyard near Shanghai in China.
Following official keel laying in April, the first of 145 huge steel blocks – together weighing a massive 26,000 tonnes – has been lifted into the dry dock for assembly, outfitting and painting.
At 200 metres long and 57 metres wide, it’s a close match to another Allseas barge, Iron Lady, but with key enhancements: a deeper operational draught, a full electric ballast system for faster load transfer operations and a significantly higher deck load capacity.
Together, Allseas’ trio of purpose-built cargo barges — Iron Lady, Braveheart and Bumblebee — will support the company’s platform removal and installation operations, delivering efficient topsides and jackets loading and transfer solutions to and from disposal yards.
The company has already started planning and preparation for what will be the largest offshore decommissioning assignment in Australian yet on behalf of Exxon subsidiary, Esso Australia Pty Ltd.
Allseas last year secured the contract to remove up to 12 retired platforms from the Gippsland Basin in the Bass Strait, with a combined weight of approximately 60,000 tonnes.
It plans to remove all the structures with another vessel, Pioneering Spirit — currently active in the North Sea — during an intense campaign beginning in late 2027.
Once safely removed, the facilities will be transferred to barges or vessels for load-in to the Barry Beach Marine Terminal in Victoria for dismantling and recycling by a separate onshore contractor.
In the meantime, Allseas is expanding its fleet with the Braveheart barge, which is expected to launch this September, with delivery scheduled at the end of 2025.
At the Chinese shipyard, the first construction phase in the dock focuses on the bottom section of the ballast pump room housing critical equipment.
Installing these blocks first allows the yard to immediately begin fitting the 1.5-metre diameter ballast pipes and four powerful ballast pumps, capable of moving nearly 10 Olympic-sized swimming pools' worth of water every hour.
Once this phase is complete, construction will move on to phase two: assembling the engine room.
Allseas also announced this month two further newbuild offshore construction vessels to enhance its fleet, to be built by Wuchang Shipbuilding Industry Group in China.
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