Kickstarting a multi-well drilling campaign for strategic partner, Arena Energy, LLC, White Fleet Drilling, LLC has deployed its newly refurbished WFD 450 jack-up drilling rig, equipped for operations at water depth of 400 ft and a drilling depth capacity of 30,000 ft.
This comes following the rig's refurbishment as part of a comprehensive US$65mn acquisition and upgrade initiative. The repaired asset with modernised specifications stands apart from existing fleets, and perfectly aligns with Arena's ambitions to unlock unexploited proven reserves.
First constructed in 1999 and previously managed by Valaris, the rig had spent seven years cold-stacked in the shallow Gulf waters. White Fleet’s substantial investment to repair and modernize the asset stands as one of the largest offshore rig refurbishments in the region in recent years. Following its christening on January 9, 2026, the rig commenced offshore drilling operations in late March.
Currently operating in the Southern Eugene Island area, the rig is slated for continued drilling across Arena's Gulf leasehold.
“This is what a long-term commitment to American energy looks like,” said Arena Co-Founder and CEO Mike Minarovic. “Nobody invests $65 million in a rig for a single drilling season. The WFD 450 will be drilling wells on the Shelf — and generating significant royalties for the federal treasury — for the next 15 to 20 years.”
Minarovic continued, “We are ‘all in’ on the future of the shallow water Gulf of America. The Shelf still holds vast potential, and the WFD 450 gives Arena the reach to unlock proved reserves that no other rig in the Gulf could access.”
By restoring and expanding offshore production capabilities across the entire depth spectrum of the shallow-water Gulf Shelf, the deployment of the WFD 450 directly reinforces American energy dominance.
At a time of geopolitical tensions and supply chain disruption, operations that enable customers to source goods and services locally can play a key role in helping them reduce operational disruption and accelerate time-to-market.
Emerson is doing just that with plans to build a new automation solutions and operations centre in the Umm Alhoul Free Zone in Qatar, to include a flow calibration lab, along with other critical automation technologies designed to help customers optimise operations, reduce turnaround time, minimise costs and accelerate project timelines.
An agreement to establish the centre was signed on the sidelines of Qatar Economic Forum (QEF) in New York City in the presence of Qatar Free Zone dignitaries.
Emerson already has a strong existing footprint of manufacturing, service and distribution locations in the Middle East across Saudi Arabia and UAE, along with an extensive network of service partners in the region. The 3,500 sq metre Emerson Middle East & Africa Service Center will expand Emerson’s local capabilities for customers in Qatar and across the Middle East and Africa, reinforcing the company’s expanding automation and industrial technology presence in the region, contributing to in-country value creation and aligning with Qatar Vision 2030 objectives around economic growth, diversification and industrialisation. This will see Qatar transformed from a hydrocarbons-based economy to an advanced, diversified and competitive global knowledge-based market, with the expansion of industrial sectors and leveraging advanced supply chains. It also aims to create a business-friendly environment capable of attracting foreign funds and technologies and of encouraging national investments.
The new facility is significant in that it will host the region’s first certified in-country flow calibration lab, with the capability of calibrating large-size flow meters for high-pressure and high-volume operations. These are extensively used in Qatar’s heavy industrial sectors such as oil and gas, chemicals, power and water to measure and monitor fluid, gas and steam transfer.
The Qatar facility will also feature:
The contol systems staging and measurement solutions services, spares inventory and training centre will open in Decemebr 2026, with the certified flow calibration lab following in early 2027.
“This new investment reflects Emerson’s strategic commitment to accelerating innovation in Qatar and supporting the Middle East’s most critical operations,” said Judson Duncan, group president of Global Sales at Emerson. “Our additional capabilities will enable customers to operate with greater agility, reliability and cost efficiency.”
Strohm has concluded a joint industry programme (JIP) in collaboration with Petrobras and Shell to qualify its Thermoplastic Composite Pipe (TCP) flowline technology.
Featuring full-scale qualification and extensive offshore field testing, the project represents the most advanced initiative worldwide to evaluate TCP flowlines under actual offshore conditions. The corrosion-free solution offers a 30-year design life and holds the potential to transform deepwater operations in Brazil and globally.
The JIP has delivered the first fully qualified flowline engineered to endure the harshest Brazilian pre-salt conditions, including severe CO₂ environments, over a 30-year operational span. Utilizing Strohm's systematic qualification framework, the programme incorporated system-representative testing to validate interactions between the pipe, end-fittings, and sealing interfaces under realistic operating conditions, ensuring predictable long-term system integrity.
Martin van Onna, Strohm’s CEO said, “The project has great strategic relevance for the subsea sector in Brazil and beyond, as it decisively solves one of the major pipeline integrity challenges identified in recent years: the risk of stress‑corrosion cracking in environments with a high CO₂ concentration. By using non-metallic TCP, corrosion is simply eliminated, strengthening system integrity and operational reliability in challenging subsea environments.”
“Strohm’s TCP flowline is designed to be installed by today’s installation vessels without the need to change anything. The installation procedures do not require material changes and the pipeline’s behaviour both on the vessel and subsea during installation is fully predictable and in line with industry practice. Strohm’s TCP can be considered as a suitable replacement for flexible lines currently vulnerable to corrosion and we are ramping up production capacity to meet the expected demand.”
Ramón Rojas, JIP programme manager at Strohm said, “The development is based on a fully integrated methodology that combines engineering design, material selection, structural analysis and full‑scale validation. This approach ensures that predicted and actual performance are aligned, providing a high level of confidence in the system’s behaviour under demanding operational conditions and guaranteeing reliability throughout its 30‑year service life.”
Philippe Noury, technical lead for the DNV verification, said, "This qualification provides the independent technical basis for moving into the planned pilot. It also gives the industry a practical example of how non-metallic flowlines can be assessed under DNV-ST-F119 for demanding, high-CO₂ deepwater service.”
Securing transaction of approximately US$840mn, Shell Offshore Inc has closed the sale of its non-operated 50% working interest in the Na Kika platform and associated fields, alongside its fully owned Coulomb subsea tieback in the Gulf of Mexico.
The offshore assets were acquired jointly by a subsidiary of Talos Energy and an affiliate of Ridgewood Energy.
Shell retains rights to uncapped upside-linked payments running through 2027, as well as overriding royalty interests (ORRI) on future production derived from new tiebacks to the Na Kika host facility.
The acquiring parties have agreed to assume defined decommissioning obligations, backed by financial security guarantees.
The divestment falls in line with Shell’s strategic focus on streamlining its upstream portfolio for lower-cost, resilient deep-water developments. After studying internal modeling, the company concluded that neither asset would contribute significantly to its long-term production profile heading toward 2030.
Operating since 2003, Shell held the semi-submersible Na Kika facility with bp, which serves as the operator and retains its 50% stake. At year-end 2025, Shell’s proved reserves stood at 4.3 million barrels of oil equivalent (boe). The Coulomb Tieback, on the other hand, has been integrated into the regional infrastructure in 2005. The asset held 7.2 million boe in proved reserves for Shell at the end of 2025.
Shell’s net entitlement share across both assets averaged approximately 37,000 boe per day during 2025.
Despite the sale, Shell maintains a prominent presence in high-margin deep-water basins, remaining the premier producer and operator in the Gulf of Mexico alongside extensive holdings in Brazil.
The United States remains one of Shell’s largest global markets, spanning major deep-water operational hubs, a nationwide retail network of nearly 12,000 branded stations, extensive LNG trading operations, and a domestic workforce exceeding 11,000 employees.
SLB has been awarded four integrated well construction contracts by Aramco to support oil and gas development across Saudi Arabia.
The global energy services group will manage end-to-end well construction services, delivering more than 450 wells over a three-year term, with an optional extension of up to two years.
"Delivering hundreds of wells across a multi-year programme and in multiple operating environments requires an integrated model that connects planning, execution and digital workflows to set new industry performance benchmarks,” said Steve Gassen, Executive Vice President of Geographies for SLB.
“Awarding SLB these advanced well construction programmes at scale reflects Aramco’s confidence in our integrated model and capabilities."
SLB said in a statement that its integrated well construction model brings together every aspect of well delivery through a technology-enabled operating model.
It combines digital drilling workflows with automated drilling, evaluation, fluids, cementing and completions products and services to improve efficiency, consistency, and well performance across diverse, large-scale drilling programmes, it noted.
The latest contract also marks a significant expansion of SLB's integrated well construction business in Saudi Arabia, building on decades of collaboration with Aramco.
The annual Offshore Well Intervention Awards Global 2026 will return to Aberdeen this November, ready to once again shine the spotlight on the greatest minds within the industry.
This year, the judges will review each entry across six different criteria, including originality and creativity; functionality and technical qualities; ease of use; impact on the industry; performance and track record; and sustainability and growth.
The awards up for grabs this year include:
Guests will be treated to an evening of networking, entertainment, a three course meal, and the chance to raise a glass with the best in the industry and celebrate the success with their peers.
The ceremony will take place at the Union Kirk, Aberdeen on 19 November, 2026. Tickets are available on the website.
The Federal Government has stepped in to ensure the abandoned Cliff Head platform off the West Australia coast remains in a safe condition, following the entry of its owners into administration in July.
Federal Resources Minister Madeleine King authorised taxpayer funding to maintain the rig, with her office giving assurances that all costs to government would be recovered from the industry.
Triangle Energy entered administration faced with estimated decommissioning liabilities for the Cliff Head oilfield and associated infrastructure of $200mn after its partner, Pilot Energy entered administration having failed to secure funding to buy out Triangle’s stake in the joint venture.
The case has echoes of the Northern Endeavour scenario, when in 2020 the government took over responsibility for decommissioning and remediating the Northern Endeavour FPSO and its associated infrastructure, after its owner went into liquidation. Six years later, the work is still ongoing. Since then, various reforms have been implemented to ensure operators carry out their decommissioning obligations and prevent a similar event occurring again. The Federal Government also imposed a levy on the Australian petroleum industry to cover the Northern Endeavour decommissioning costs.
Conservation Council of WA (CCWA) Executive Director Matt Roberts said taxpayer funded maintenance of the Cliff Head Oil platform would have been avoided by stronger oil and gas decommissioning laws.
“The Federal Government should not be using Australian taxpayer money to maintain the fossil fuel industry’s abandoned infrastructure.
“What we need now is a clear plan and timeline to recover these funds from industry and meaningful, legislated changes to avoid this happening again in the future.”
Noting that the Federal Government is planning reforms to decommissioning legislation he added, “With $60 billion in decommissioning liabilities sitting offshore across Australia to be worked through in the decades ahead, we must get these reforms right.”
Law firm Clyde & Co, in an article on its website comments, “It appears that Triangle's collapse, and the current uncertainty surrounding responsibility for the Cliff Head decommissioning, is a consequence of matters which occurred under the pre-reform regulatory regime rather than a failure of the current regulatory regime.
“Triangle and Pilot’s acquisition of the Cliff Head oil field and its associated infrastructure occurred before the Walker Review reforms and in circumstances where the pre-reform regulatory regime did not provide for adequate regulatory oversight. It remains to be seen whether any other late-life offshore assets acquired by smaller operators under the pre-reform regime will emerge with solvency concerns as production ceases and decommissioning liabilities crystallise.
“It may be that the original developers of Cliff Head avoid decommissioning liability in this instance due to limitations on the retrospective effect of the trailing liability reforms.”
Clyde & Co added that the expanded trailing liability regime means that the regulator may also look to related persons where appropriate with respect to decommissioning, as well as the two companies concerned.
“Triangle and Pilot’s collapse may cause regulators, financiers and project proponents to scrutinise more closely whether adequate security or funding arrangements are in place to meet both operational and eventual decommissioning liabilities for late-life offshore assets,” Clyde & Co concluded.
Advanced oceanographic technology is driving the rapid expansion of South America’s offshore energy sector, particularly in Brazil’s deepwater pre-salt fields and Guyana’s Stabroek Block.
Effective operations across harsh marine environments require real-time ocean data for supporting subsea construction, drilling and vessel safety. Operators are increasingly relying on wave monitoring and oil spill detection systems to manage operational risks and ensure environmental protection across the region.
Accelerating commercial momentum in South America, the Norwegian ocean technology company Miros has reported for the year several wins in double-digits across the region.
These contracts were secured during the end of 2025, and continue to generate value for the company. The first three quarters of 2026 have set a positive tone for the company's future, with most activities concentrated in Brazil alongside deployments linked to offshore operations in Guyana.
The deployments span real-time wave and ocean monitoring and oil spill detection, supporting operations including subsea construction, offshore vessel operations, drilling-related activities and environmental response.
While these agreements comprise several exisiting customers, deals were secured with new clients as well. Miros got several bookings for services extensions in additional vessels and assets, including offshore support vessels, marine response vessels and drilling-related assets.
Marius Five Aarset, CEO of Miros, said, “What is particularly encouraging is not simply the number of wins, but the pattern behind them. We are seeing new customers adopting Miros’ technology, existing customers expanding to additional vessels, and growing activity in Brazil.”
“Across subsea operations, drilling, vessel operations and oil spill response, the common requirement is reliable real-time information that supports safer and better-informed decisions offshore.”
Andrew Wallace, Regional Commercial Manager at Miros, said, “At Miros we have a long-term commitment to Brazil and the wider South American market. We continue investment in the region through our technology, engineering expertise, commercial resources and direct customer engagement, supported by our trusted local partners who strengthen our regional reach and delivery capabilities.
"The continued activity strengthens Miros’ presence in South America, with Brazil at the center of its regional growth and further opportunities across offshore energy, vessel operations and environmental monitoring.”
While carrying a history of severe geopolitical instability, Libya's resilience in still being able to attract global investment interests speaks volumes about the richness of its reserves
Known to hold Africa's largest proven oil resources, Libya moves North African supply dynamics. International oil companies are increasingly returning to reactivate dormant fields and tap into high-potential basins. Central to this resurgence is the Sirte Basin, a historically prolific region offering significant infrastructure proximity.
Recently, the country has reported several successful appraisals, marking a critical turning point for international investment, signaling restored commercial confidence and renewed momentum in Libya’s long-term energy output goals.
OMV has classified the Essar well in Libya’s Sirte Basin as commercially viable following technical and economic evaluations. Previously, the Libya NOC too approved the discovery's commercial viability.
The well lies in the concession area C 103, where OMV holds 12% interest.
With an indication of total recoverable resources reaching up to 45 million barrels of oil, the reservoir is being prepared for development by Zueitina Oil Company. It will be easier to hit production timelines from thew concession sooner as it lies adjacent to existing production and processing facilities, ensuring cost-efficiency as well. The discovery highlights Libya’s potential as one of Africa’s most important energy regions and marks another milestone in the long-standing partnership between OMV and the NOC.
“The Essar discovery is a major milestone for OMV and our partners at the NOC. It confirms not only Libya’s considerable potential, but also the value of long-term partnerships, technical excellence, and our unwavering commitment on the ground. Strategic collaborations such as this are essential to providing the energy the world needs. I am proud of what we have achieved together and look forward to the next chapter in Libya”, said Berislav Gaso, OMV executive vice president for energy.
OMV holds Libya strategically important as part of its upstream growth interests in North Africa. The company has been an active player in Libya for around 50 years and is among the country’s long-standing international energy partners. It resumed operations in the country in 2024, after a hiatus of more than ten years.
OMV has extensive experience in the exploration and production of oil and gas in North Africa and relies on close cooperation with local partners as well as the continuous optimization of existing assets. Libya holds Africa’s largest proven oil reserves and ranks among the world’s most significant oil-producing countries.
Australia’s Department of Industry, Science and Resources has reported back on common issues and concerns regarding the decommissioning process, following an industry and stakeholder consultation process as part of its reforms overhaul.
It comes as Australia seeks to tighten financial and regulatory safeguards around offshore oil and gas decommissioning, amid concerns that companies could leave taxpayers exposed to costly clean-up liabilities.
The Department said it was running its targeted consultation on the practical workings of proposed regulatory design amid updates to offshore decommissioning and financial assurance reforms.
Common themes to emerge from stakeholders included the need for:
• Earlier and regularly updated decommissioning planning
• Robust and credible decommissioning cost estimates
• Greater public transparency of decommissioning information
• Stronger financial assurance requirements
• Clear and effective enforcement options capable of intervening where required
• Clear regulatory triggers and expectations
The consultation process focused on a range of issues including decommissioning planning; financial planning and assurance; decommissioning and financial capacity risk assessments;
compliance and enforcement tools; and title surrender.
The Department said that it received 38 submissions and published 30 responses, while issues identified have “directly shaped” the proposed model, including its emphasis on:
• Staged planning
• Greater transparency
• Effective compliance and enforcement tools
• A proportionate, risk-based regulatory approach
“We are now conducting roundtables and meetings with stakeholders to test the regulatory design for the reforms,” the Department noted.
“The focus of this consultation is on technical and implementation issues. This includes how the model would operate in practice across different project types and life cycle stages.”
It said this targeted feedback would help reduce the risks of “unintended consequences” and ensure a robust, proportionate and balanced regulatory regime.
“Our reforms seek to ensure industry decommissions offshore infrastructure in a timely, safe and environmentally responsible way. This includes remaining responsible for the risks and liabilities of offshore activities,” the Department said in a statement.
There is expected to be a further consultation on the legislative changes in 2027.
Tackling millions of acres of ocean waters that make up the Outer Continental Shelf (OCS) is no mean feat and will only turn more challenging if not addressed in an optimised manner.
The United States Department of the Interior (DoI) is hence proactively initiating structural realignments so that resource leasing is done in an environmentally responsible manner. A clear administrative structure in place will eliminate regulatory friction while upholding safety standards.
In a significant consolidation move of its offshore regulatory agencies for enhanced oversight across the OCS, the DoI has announced the unification of the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) into a single Bureau -- the Marine Minerals Administration (MMA).
This move will simplify supervision of activities in the OCS due to effective administration from streamlined governance as MMA begins to operate as part of the DoI.
MMA was formerly known as Minerals Management Service (MMS), whose operations were split across the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE). While at BOEM MMS administered offshore energy and minerals leasing, resource evaluation and environmental review, at BSEE it was responsible for overseeing operational safety, environmental enforcement, resource conservation and regulatory compliance.
When independently operating, a lot of complications hampered the operations of both Bureau. There were unnecessary bureaucracy and administrative systems that were only obstructing the DoI's capacity for strategic deployment, and could simply be done without. Reunification of BOEM and BSEE into a single Bureau will reduce overhead, enhance the deployment of subject matter expertise across the entire mission area and deliver stronger safety outcomes for the workers and communities who depend on safe and responsible OCS operations. It will allow DoI a holistic approach in addressing safety and environmental concerns throughout the OCS for all leasing, exploration, development, production and decommissioning processes, which will improve leadership decision-making.
The MMA will cover all aspects of DoI's offshore energy and mineral resource management and conservation, safety oversight, environmental enforcement and related activities on the OCS. The position will be spearheaded by a Director under the supervision of the Assistant Secretary – Land and Minerals Management (AS-LMM).
A North Sea operator improved the reliability of its offshore production operations after deploying a new electric submersible pump (ESP) system supported by Halliburton’s Summit ESP service and digital monitoring technologies
The deployment addressed challenges with the operator’s previous ESP supplier, including missed delivery timelines, limited equipment availability, mechanical failures and high intervention costs. The operator also required a reliable solution that could be installed on an active production platform using hydraulic workover (HWO) unit operations.
According to a Halliburton case study, the operator needed an ESP system that could be delivered quickly, installed without disruption and supported through continuous monitoring and optimisation.
Addressing offshore ESP reliability challenges
The operator’s previous ESP systems had experienced limited stock availability and extended delivery times, while mechanical failures had contributed to operational challenges.
Installation also presented specific risks. Capillary chemical injection lines had been damaged during previous installation activities, creating concerns about the long-term performance of the ESP system.
In addition, offshore cybersecurity requirements added complexity to the deployment of digital monitoring and remote optimisation capabilities.
To address these challenges, Summit ESP, a Halliburton service, worked with the customer to conduct a detailed factory assessment of each ESP component.
The team designed a custom protector flange to safeguard the capillary line. The component was manufactured locally in Emmen, the Netherlands.
ESP system delivered ahead of schedule
Early delivery of the ESP system enabled comprehensive fit-up testing with HWO tools before offshore installation. This helped verify compatibility and prepare the equipment for deployment on the production platform.
Halliburton’s global field service team subsequently installed the system, removed the failed equipment and commissioned the replacement ESP system.
The installation achieved 100% KPI compliance, while the Intelevate® platform, powered by the Summit Knowledge® digital ecosystem, provided real-time data, health checks and optimisation recommendations from the start of operations.
The system was delivered one month ahead of schedule, while the deployment recorded zero non-productive time (NPT).
The Intelevate platform also provided 24 hours of daily real-time monitoring and optimisation.
Digital monitoring supports offshore operations
The deployment marked the first use of Halliburton’s Intelevate digital platform in the North Sea, according to the Halliburton case study.
The platform provided continuous visibility into the ESP system and supported 24/7 optimisation from day one.
The early arrival of the ESP system also allowed additional pre-checks and in-country fit-up testing before offshore installation. This confirmed compatibility with the HWO equipment and helped eliminate risks associated with non-productive time and minimise deferred production.
Restoring ESP performance offshore
The replacement ESP system met production targets and restored reliability to the operator’s offshore operations.
Continuous support through the Intelevate platform helped maintain operational efficiency through real-time monitoring and optimisation.
The customer acknowledged the service quality, with the deployment representing a milestone in the operator’s offshore ESP operations.
