In June 2025, Equinor and Shell announced the creation of Adura, a joint venture poised to become the UK North Sea’s largest independent oil and gas producer.
First revealed in December 2024, Adura merges the offshore oil and gas assets and expertise of two energy giants to sustain domestic production and enhance UK energy security.
Headquartered at the Silver Fin building in Aberdeen, Adura is deeply rooted in the city’s legacy as the UK’s energy capital.
The name Adura, combining the “A” of Aberdeen with the “dura” of durability, reflects the venture’s foundation in the granite-strong energy community and its commitment to the North Sea’s long-term future.
The company will manage key assets, including Equinor’s stakes in Mariner and Buzzard and Shell’s interests in Shearwater, Penguins, Gannet, Nelson, Pierce, Victory, Clair, and Schiehallion, alongside various exploration licenses.
Adura is projected to produce over 140,000 barrels of oil equivalent per day in 2025, with ambitions to reach 200,000–220,000 boed within five years as new projects come online.
Since its naming, Adura has progressed toward its planned launch by the end of 2025, pending regulatory approvals.
Approximately 1,300 employees from Equinor and Shell are transitioning to the venture, with Shell staff already based at Silver Fin and Equinor’s workforce relocating from Kingswells in phases through 2026.
This move reinforces Aberdeen’s role as a global hub for energy expertise. Equinor’s £6bn in deferred tax losses will bolster Adura’s financial flexibility, while Shell’s robust production capacity enhances cash flow, positioning the venture for cost-competitive operations in a maturing basin.
Camilla Salthe, senior vice president Equinor UK Upstream, said, “We are so pleased to have reached this major milestone in the creation of the new company with Shell. For us, the name Adura represents the very heart of this company and speaks to its people and place within the energy community anchored in Aberdeen, alongside its longevity and commitment to the North Sea.”
Simon Roddy, senior vice president Shell UK Upstream, said, “Adura takes an exciting step forward today as we unveil its new name – rooted in a proud history in the North Sea and looking forward with confidence to delivering secure energy for the UK for many years to come.When Adura launches later this year it will become the UK’s largest independent producer. Through combining assets and expertise, we will create a robust portfolio, with a shared purpose, to unlock long term value.”
Expro, a global provider of energy services, has achieved a significant breakthrough in its international operations with the successful delivery of the world’s first fully remote five-plug cementing operation in Saudi Arabia. This marks a major step forward in the company’s strategic expansion across the Middle East and showcases its dedication to innovation, safety, and advanced engineering in the well construction space.
The landmark operation was carried out using Expro’s Generation-X Remote Plug Launcher (RPL) and the SkyHook cement-line make-up device—two proprietary technologies designed to automate complex cementing processes. This fully hands-free system enabled a multi-stage cementing job to be completed without any red-zone entry or man-riding operations, setting a new benchmark for operational safety and remote performance in the field.
This latest achievement builds on Expro’s initial cementing job in the Kingdom, completed in January. That successful operation laid the groundwork for rapid growth in the region, culminating in the delivery of this more complex five-plug job in May. Both operations reflect Expro’s deliberate progression from market entry to technology leadership, highlighting the scalability, precision, and reliability of its automated cementing solutions in high-demand environments.
The recent five-plug operation involved cementing a 9-5/8” casing in a high-pressure gas well—the longest of its kind in the field. All five components were pre-loaded into the modular Generation-X RPL in a controlled environment and launched remotely at the well site with high accuracy. This significantly reduced rig time, eliminated high-risk manual tasks, and improved cement placement and zonal isolation-critical factors in maintaining long-term well integrity.
“Our entry into Saudi Arabia is more than just geographic expansion – it’s about transforming cementing operations through advanced engineering,” said Jeremy Angelle, Vice President of Well Construction at Expro. “This breakthrough showcases our Generation-X and SkyHook technologies as world-class innovations that drive measurable safety and efficiency gains.”
Additional deployments of these technologies across the region have further validated their performance, with one customer achieving cement displacement rates of up to 13 bpm through the top drive—delivering cleaner wellbores, quicker casing-to-cement transitions, and shorter wellbore static times.
“Both the Generation-X launcher and SkyHook system were designed with safety, control, and field adaptability in mind,” Angelle added. “To see them deliver such strong results in a new region is a proud moment, and a signal of what’s possible as we grow our well construction capabilities globally.”
Expro continues to invest in expanding its footprint in Saudi Arabia and beyond, aligning its offerings with evolving customer needs in oil, gas, and geothermal markets. With proven success and growing demand, its remote cementing solutions are now poised for wider global adoption.
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.
Norway is moving ahead with new oil and gas exploration in an effort to sustain long-term production on the Norwegian continental shelf.
The Ministry of Energy has officially initiated the process for the 26th licensing round, opening the door for companies to nominate acreage for potential development.
“Norway will remain a long-term supplier of oil and gas to Europe, while the Norwegian continental shelf will continue to create values and jobs for our country. To deliver on this commitment, we must make more discoveries — and to make more discoveries, we must explore. That is why today we are launching the process for the 26th licensing round for awarding new production licenses,” said Minister of Energy Terje Aasland.
The announcement coincides with Aasland’s inauguration of the Johan Castberg field in the Barents Sea, one of the largest new projects on the shelf in recent years.
Much of Norway’s remaining oil and gas resources have yet to be proven, making new exploration critical. Without fresh discoveries, production is expected to gradually decline from the early 2030s. Alongside exploration, improved recovery techniques and the development of profitable finds are seen as essential to slowing that trend.
The government has pledged to keep annual licensing rounds at the centre of its strategy. The Awards in Predefined Areas (APA) rounds, which cover most opened and available acreage, remain the backbone of policy. Numbered rounds, such as the 26th, apply to areas outside the APA zone.
“The Labour Party Government has a long-term perspective on the further development of our continental shelf. Europe will need oil and gas for a long time to come. Our goal is to ensure that we can supply oil and gas produced with low emissions for as long as there is a demand. Annual licensing rounds going forward are important to achieve this,” Aasland added.
As part of the 26th round, the Norwegian Offshore Directorate has been tasked with managing the nomination process, allowing licensees to propose areas for inclusion. Their input, combined with the Directorate’s own subsurface assessments, will guide recommendations to the Ministry on which acreage should ultimately be made available.
A new report by an alliance of unions and leading environmental organisations has recommended the establishment of a nation-first decommissioning hub in Western Australia to manage the state's growing number of retired offshore oil and gas assets.
The WA Can’t Wait report, a collaboration between Greenpeace Australia Pacific, Unions WA, Conservation Council WA, Maritime Union of Australia - WA Branch, The Wilderness Society, Australian Manufacturing Workers Union - WA Branch, Electrical Trades Union - WA Branch, argues that a WA decommissioning hub would deliver thousands of secure, skilled jobs, protect marine ecosystems and coastal communities, and bring scrap steel and other materials into local domestic circular supply chains.
Recommendations include:
• A decommissioning hub be built in Western Australia, near current fossil fuel infrastructure and where green recycling facilities can be established
• Oil and gas operators are held financially responsible and a fully industry-funded clean-up be mandated
• Existing laws are strengthened and enforced to ensure a full and timely decommissioning
• The safety of workers and the environment is prioritised
• Investment in ports, recycling facilities and local workforces is increased to support decommissioning and emerging offshore wind and other renewable energy industries.
Geoff Bice, Greenpeace Australia Pacific WA Campaign Lead, pointed out that 89% of Australia’s 5.7 million tonnes of offshore oil and gas infrastructure is in West Australian waters.
“A decommissioning hub is WA-positive, and the industry should foot the bill for their own mess. This isn’t just a clean-up plan, it’s a once-in-a-lifetime opportunity to build a world-leading industry.”
Matt Roberts, Conservation Council of Western Australia Executive Director, said,“50% of Australia’s offshore oil and gas infrastructure is due to be decommissioned by 2030 and most of it is in WA. It is critical that companies are held to account to deliver on their environmental responsibilities. There are also huge opportunities for new jobs in decommissioning and metals recycling. These are the jobs of the future that will help us transition to renewable energy."
Will Tracey, Maritime Union of Australia WA Secretary, said, “We welcome this practical, worker and community-focused contribution to solving a national decommissioning bottleneck. This is how we keep high value jobs in WA and secure economic strength for decades to come, building a bridge between the energy past and a just, sustainable future. It’s time for the government to act on what workers and communities are calling for: full removal, local recycling, and a Future Made in Australia that starts in WA.”
Sunda Energy has updated investors on its latest well planning activities for the Chuditch field, a material asset in the Timor Sea gas fairway, in Timor-Leste.
Following an announcement on 16 June 2025 of the postponement of drilling of the Chuditch-2 well by subsidiary SundaGas Banda Unipessoal, Lda., the UK-listed exploration and production company said it has engaged with local authorities concerning the realisation of the drilling campaign, now likely to be in the first half of 2026.
Sunda Energy executives visited Dili in July for meetings with the Minister of Petroleum and Mineral Resources, upstream regulator Autoridade Nacional do Petróleo (ANP) and state-owned joint venture partner TIMOR GAP.
It reported that discussions were “constructive and positive” with all parties committed to completing drilling preparations and executing the campaign on the revised timeline.
In the meantime, it is putting in place a team to assist in the planned campaign, including assessing a revised proposal from the Timor-Leste helicopter company for support on the upcoming offshore work.
The company is also engaged with a number of rig operators in preparation for a full tender exercise to enable the retimed drilling campaign, while the process of securing an environmental permit continues.
The Chuditch production-sharing contract is located 185km south of Timor-Leste, 100km east of the producing Bayu-Undan field, and 50km south of the Greater Sunrise potential development.
The shallow water area contains the Chuditch-1 gas discovery drilled by Shell in 1998, which encountered a 30m gross gas column.
The initial aim is for the drilling of an appraisal well, to be followed by a production flow test (DST) to establish potential flow rates for any anticipated future development.
Separately, Sunda Energy said in a statement that it is “actively engaged” in the pursuit of a number of new business initiatives without identifying details.
It said the target opportunities are “potentially material” and would be “highly impactful” to the company if secured.
Sunda Energy also has applications outstanding on two blocks in the Sulu Sea, offshore Philippines, pending final Presidential signature.
“It is understood that there are now nine new Service Contracts pending signature, including the two in which Sunda will participate, and there is an expectation that these will all be signed in the near future, as a trigger for renewed oil and gas activities in the Philippines,” the statement noted.
ConocoPhillips Skandinavia AS (ConocoPhillips) has awarded Halliburton a significant five-year contract to provide a full range of well stimulation services aimed at boosting well performance and enhancing reservoir productivity. The agreement also includes three optional extension periods, potentially extending the collaboration well beyond the initial term.
As part of the contract, Tidewater’s vessel, North Pomor, will undergo a major transformation into a state-of-the-art stimulation vessel, purpose-built to deliver efficient and effective offshore well stimulation operations in the challenging conditions of the North Sea. The vessel upgrades will feature advanced technology, including Halliburton’s proprietary Octiv digital fracturing services, which are designed to optimise stimulation equipment performance, streamline operations, and improve overall efficiency.
The project represents a key step in Halliburton’s strategy to offer integrated, technology-driven solutions for complex offshore developments. By combining vessel capabilities with cutting-edge digital tools, Halliburton aims to deliver consistent, high-quality stimulation treatments that help operators unlock additional value from existing reservoirs while supporting safe and efficient offshore operations.
According to the company, this latest contract award underscores Halliburton’s market leadership in stimulation services and its ability to tailor solutions to the specific needs of offshore environments. For ConocoPhillips, the partnership is expected to play an important role in maintaining and enhancing production levels in the North Sea, a region where operational efficiency and innovation are essential to long-term energy output.
Mark Dawson, senior vice president, Halliburton Completion and Production division, said, "We are pleased to strengthen our longstanding relationship with ConocoPhillips through this important award. This contract win complements our extensive experience in well stimulation and highlights how we execute globally. The combination of our latest technology and our focus on automation and safety is how we maximise value for our customers."
French energy giant TotalEnergies has secured a 25% stake in a portfolio of 40 offshore exploration leases in the U.S. Gulf of Mexico, operated by Chevron. The agreement strengthens TotalEnergies' presence in U.S. offshore energy projects and supports its goal of boosting oil and gas production by 3% annually through 2030, focusing on low-cost, low-emissions output.
The newly acquired federal leases are located across three major areas: 13 blocks in Walker Ridge, 9 in Mississippi Canyon, and 18 in East Breaks. These zones are known for their resource-rich deepwater potential, with Chevron continuing as the operator of the assets.
TotalEnergies already holds minority interests in four Chevron-operated offshore fields in the Gulf of Mexico, further reinforcing its long-term collaboration with the Texas-based energy company.
In the liquefied natural gas (LNG) sector, TotalEnergies is the leading U.S. LNG exporter, managing over 10 million metric tons per year under long-term contracts. Historically, the company has sourced LNG from local producers, but recently it has shifted toward more upstream investments.
In 2024, TotalEnergies also acquired stakes in two Texas shale gas fields from Lewis Energy Group. This move gives the company direct access to natural gas at the U.S. Henry Hub price benchmark—an important step to ensure cost-efficiency in LNG exports amid changing market conditions.
This latest offshore deal marks a significant step in TotalEnergies' strategy to expand in low-carbon oil and gas production while ensuring energy security and cost stability through integrated supply chain management.
Since announcing the acquisition of Harbour Energy's Vietnam business in July, EnQuest has wasted no time in getting to grips with its new assets.
The company recently confirmed that several well intervention projects had gone ahead and been successfully completed.
In July, EnQuest confirmed that it had completed the acquisition of Harbour Energy's business in Vietnam for a 53.125% equity interest and operatorship of the Chim Sáo and Dua production fields (Block 12W) in a transaction valued at around US$85mn.
Since signing the deal, EnQuest reported that the Vietnam asset team has successfully completed a planned annual maintenance shutdown, on time and within budget, and executed three of six scheduled well intervention scopes, which have added around 1,200 barrels of oil equivalent per day (boepd) of gross production.
“Net asset production in the first half of 2025 averaged 5.7 kboepd, with the potential for further in-year upside relating to well intervention activity and performance and the positive impact of a production-enhancing chemical soaking process undertaken during the shutdown,” a recent EnQuest statement noted.
The Vietnam acquisition was soon followed by a separate announcement with EnQuest awarded a production-sharing agreement (PSC) for offshore Block C in Brunei Darussalam, as it grows its footprint across the region.
Block C hosts the condensate-rich gas discovered fields of Merpati, Meragi and Juragan.
Alongside another recent award of PSCs in Indonesia, EnQuest continues to grow its business beyond its core Malaysia operations, where it recently celebrated 10 successful years.
In June, the company was recognised at at the Petronas Emerald Awards ceremony in Kuala Lumpur as Malaysia’s ‘Operator of the Year’ and also landed an additional award for ‘Abandonment Excellence’.
After announcing the Vietnam acquisition, EnQuest CEO, Amjad Bseisu, said South East Asia remains central to the group’s overall growth and diversification strategy.
“We are excited by the opportunity to utilise our proven operating expertise to optimise, enhance and extend the Block 12W assets in Vietnam,” he said.
South Natuna Sea Block B has seen a marked boost in first production from MedcoEnergi's Terubuk Well Head Platform M Project.
Terubuk's production capacity has reached 6,600 bopd of oil and 60 mmscfd of gas, neeting significant energy security and production targets.
Topside fabrication for the project was completed within six months, well below the average offshore project duration of 10 - 12 months. All phases of the project were executed entirely by Indonesian talent, underscoring the nation's ability to deliver world-class solutions in the energy industry.
The Terubuk Project, which includes WHP-L and WHP-M saw a quick turnaround with the implementation of MedcoEnergi's Digital Microwave Radio and Integrated Control & Safety Systems for remote monitoring and control, to enhance operational efficiency and reliability.
Director and chief operating officer MedcoEnergi, Ronald Gunawan, said, "We appreciate the full support from the Government, SKK Migas, the Ministry of Energy and Mineral Resources, and all involved parties, which enabled WHP-M to reach the sail away and onstream stages in a relatively short time. The innovation in this project management sets a new standard for rapid, efficient, and sustainable marginal field development, and reflects the capabilities of our nation's talent in delivering energy projects.”
ExxonMobil Guyana has started production at Yellowtail field, the fourth oil development in Guyana’s offshore Stabroek block.
Yellowtail’s ONE GUYANA floating production storage and offloading (FPSO) vessel joins the Destiny, Unity, and Prosperity FPSOs, bringing total installed capacity in Guyana to more than 900,000 barrels of oil per day.
“Yellowtail’s ahead-of-schedule startup is a significant milestone for ExxonMobil and the people of Guyana,” said Dan Ammann, President of ExxonMobil Upstream Company. “With Guyanese making up more than 67% of the country’s oil-and-gas workforce and over 2,000 local businesses engaged, this project reflects our deepening roots in the country and our shared commitment to long-term, inclusive growth.”
The ONE GUYANA is the largest FPSO on the Stabroek block to date, with an initial annual average production of 250,000 bopd and a storage capacity of two million barrels. Oil produced from the FPSO will be marketed as Golden Arrowhead crude.
By 2030, ExxonMobil Guyana expects to have total production capacity of 1.7 million oil equivalent barrels per day from eight developments.
ExxonMobil has experienced remarkable success in Guyana’s deepwater developments, achieving record production in 2024. In five years, the company has started up four complex offshore mega-projects under budget and ahead of schedule – while advancing plans for four additional projects by the end of the decade.
ExxonMobil Guyana Limited operates the Stabroek block and holds a 45% interest, with Hess Guyana Exploration Ltd. holding 30%, and CNOOC Petroleum Guyana Limited holding 25%.
Integrated energy services giant, Kent, has been awarded a technical advisory services contract by the Australian Government to support the permanent plugging and abandonment of the Laminaria-Corallina fields in the Timor Sea.
The contract also includes advisory services for the removal of associated subsea infrastructure within the fields.
The award underscores Kent’s position as a trusted decommissioning partner following its existing work conducted on the Northern Endeavour FPSO facility, as well as its expanding footprint within the APAC region. Under the initial two-year contract, Kent will deploy a team of technical and regulatory experts to provide strategic and operational support throughout the decommissioning phase.
Michael Costello, Executive Vice President – Development, APAC & Americas, said, “This contract is a testament to the trust the Australian Government has placed in Kent’s decommissioning expertise. We are proud to continue supporting the safe and responsible transition of offshore assets, prioritising environmental outcomes and technical integrity at every stage.”
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