In March 2008, Libya produced 1.75 million barrels of oil per day (bpd). Since then, thanks to political instability, it has never reached that figure again. Will 2025 be the year Libya goes back to its peak crude oil production?
The country is the richest in terms of oil reserves in Africa, and its offshore oil and gas sector is a cornerstone of its energy industry.
In the last few years, some significant developments have begun to shape the Libyan oil market, which could signal positive news for the industry.
Recent developments in offshore fields like Bouri, Bahr Essalam, Sabratha, and Al Jurf, alongside new exploration initiatives, highlight Libya’s efforts to bolster offshore production through well intervention and infrastructure upgrades.
In fact, in December last year, Libya produced 1.4 million bpd, which is its best performing figure since 2013. The country has ambitions to reach 1.6 million bpd by year end.
A key development is the February resumption of gas production at Well CC18 in the Bahr Essalam offshore field, operated by Mellitah Oil and Gas (a joint venture between Libya’s National Oil Corporation (NOC) and Eni).
This restart likely involved well interventions such as coiled tubing or acid stimulation to address reservoir issues like scale buildup, ensuring consistent gas flow to the Mellitah treatment plant for domestic and European markets.
Similarly, the Sabratha Compression Project, in its execution phase with startup planned for late 2025, aims to enhance gas production.
Compression projects often require interventions like gas-lift optimisation to maintain well productivity, underscoring the role of advanced techniques in Libya’s offshore strategy.
The Bouri Gas Utilisation Project, another significant initiative, focuses on increasing gas output from the Bouri field, one of Libya’s largest offshore assets.
Operated by Eni and NOC, this project involves installing equipment to optimise production, likely supported by interventions such as perforating or chemical treatments to counter declining reservoir pressure.
Eni’s Structures A&E Project, with drilling set for mid-2025, channels gas from two offshore fields to Mellitah.
This project, involving new platforms and subsea infrastructure, will likely require well interventions like hydraulic fracturing to optimise new wells and ensure long-term productivity.
The adoption of AI-driven technologies by Eni suggests potential advancements in intervention efficiency, such as real-time monitoring to guide coiled tubing or wireline operations.
In January 2025, NOC launched its first exploration bid round in 17 years, offering 22 onshore and offshore blocks, including areas in the offshore Sirte Basin.
This initiative, attracting interest from companies like Repsol and BP, signals future offshore development.
New wells will eventually require interventions like well testing or stimulation to bring them online efficiently, building on Libya’s estimated 48 billion barrels of oil reserves, much of which lies offshore.
However, political instability poses significant risks. Only last month, Libya’s eastern-based government threatened a force majeure on oil fields and ports, following attacks on NOC facilities.
This echoed a 2024 shutdown that halted 700,000 bpd, impacting offshore fields like Al Jurf.
Such disruptions necessitate well interventions to restore production post-shutdown, as seen in Al Jurf’s history of workovers after prolonged closures.
Despite these challenges, Libya’s US$3–4bn investment plan for 2025 prioritises offshore infrastructure and interventions to achieve its production targets, reinforcing the sector’s critical role in the nation’s energy landscape.
Subsea 7 has received a subsea contract in West Africa
This contract will see the company transporting and installing flexible pipelines, umbilicals, and associated subsea components for the connection of a floating production, storage and offloading (FPSO) vessel. It will also cover the pre-laying activities for an upcoming drilling campaign.
Project management and engineering work will begin immediately at Subsea7’s offices in Sutton, UK and Suresnes, France, and offshore activity is expected to start in 2026.
Jerome Perrin, Vice President Africa, Middle East, and Turkiye for Subsea7, said, “Our close and agile collaboration with our clients allows us to make possible cost-effective and reliable offshore solutions for their needs. We are pleased to be able to support this client in executing such a strategically important project in West Africa. ”
Aker Solutions has successfully deployed an autonomous drone system on Aker BP’s Edvard Grieg platform in the North Sea, enabling frequent, remote inspections controlled from an onshore centre in Stavanger.
The company recently achieved a milestone by completing its first offshore beyond-visual-line-of-sight (BVLOS) drone operation.
The inspection flight, conducted by a drone stationed on the platform, utilised autonomous navigation and advanced sensors to capture high-resolution imagery and data, marking a significant step toward fully autonomous offshore inspections.
The drone system includes an offshore docking station, supporting infrastructure, and custom software developed by Aker Solutions, complemented by an onshore control room.
It integrates airspace and AIS monitoring, along with two-way communication with the Helicopter Landing Officer (HLO) and platform leadership, ensuring seamless coordination.
By combining autonomous drones with AI-powered analytics, the system enables frequent, highly accurate inspections.
The drone captures consistent, precisely positioned images and videos, facilitating continuous equipment monitoring.
This allows for early detection of wear, corrosion, or other issues, enabling proactive maintenance to prevent escalation.
Autonomous drones, machine learning, and robotics are central to Aker Solutions’ digital strategy, which focuses on enhancing project execution, developing innovative services, and building a digitally ready organisation grounded in advanced data and software technology.
“We believe autonomous drones will revolutionise how inspection and maintenance are performed in the energy industry. Permanently deploying a drone on an oil platform — combined with robotics, AI, and digital technologies takes offshore maintenance to a new level, improving safety, reducing costs, and increasing efficiency across offshore asset management,” said Anja Dyb, SVP Life Cycle Services, Aker Solutions.
“Aker BP's operational strategy is based on the assumption that robotics and drones will be an integral part of observation, inspection and task executions offshore. These technologies will operate autonomously or remotely, either on-site or from land. The successful remote-controlled offshore drone operation at the Edvard Grieg platform, executed by Aker Solutions, is an important milestone for Aker BP as well," said Thomas Øvretveit, director of operations at Aker BP.
“We estimate that autonomous drones can reduce inspection costs by up to 70% and deliver detailed insights within hours — a process that traditionally takes days with manual drone operations,” said Joachim Hovland, head of drones and robotics.
MODEC has been awarded a contract by ExxonMobil Guyana to develop a floating production, storage and offloading (FPSO) vessel for the Hammerhead project.
MODEC will be delivering the contract in two phases, starting with front-end engineering and design (FEED) for phase one, followed by engineering, procurement, construction and installation (EPCI) for phase two.
Awaiting relevant government and regulatory approvals, the contract currently stands as a limited notice to proceed (LNTP) by ExxonMobil Guyana. This allows MODEC to begin the designing-related activities to meet the project startup deadline in 2029 following approvals. The second phase is subjected to further approvals as well as project sanction by ExxonMobil Guyana Limited and its Stabroek Block co-venturers.
Simultaneously, the Operations and Maintenance Enabling Agreement (OMEA) for MODEC’s Guyana fleet has been established to enable the operations and maintenance of multiple FPSOs under a long-term contractual arrangement.
The Hammerhead FPSO will have the capacity to produce 150,000 barrels of oil per day (bopd), along with associated gas and water. It will be moored at a water depth of approximately 1,025 meters using a SOFEC Spread Mooring System.
MODEC Group President and CEO, Hirohiko Miyata, said, "We are incredibly honored and excited to have been awarded this contract. It is a testament to our team's dedication, expertise, and commitment to delivering innovative and reliable offshore floating solutions. We look forward to collaborating closely with ExxonMobil Guyana to ensure the successful delivery of this second FPSO, contributing to the advancement of the offshore energy sector in Guyana."
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South East Asia’s decommissioning challenge is at a pivotal point. With an estimated 1,500 platforms and 7,000 wells nearing decommissioning by 2030, it is a challenge that is coming into sharp focus. But which country faces the greatest test?
While Southeast Asia is a region with profound market differences, each of the main oil and gas-producing states faces a stern test ahead. According to recent insight article by Bureau Veritas South East Asia, the decommissioning journey ahead will not be simple, but with billions of dollars at stake, sustainable, economic and effective solutions must be found.
With over 630 offshore platforms, many of which are over 40 years old, Indonesia faces a great challenge ahead. Despite its comparatively limited decommissioning experience, Indonesia’s regulatory body, SKK Migas, is focused on enhanced oil recovery initiatives and maximising output from existing assets before decommissioning, notes Bureau Veritas, a world leader in testing, inspection and certification services. However, initial projects such as the Anoa field’s decommissioning and the removal of the Belanak floating storage and offloading unit have provided important learnings for future activity, it adds.
Brunei is home to some of the oldest oil and gas infrastructure anywhere in the wider Asia Pacific region. It is prioritising the phased abandonment of its shallow-water fields, including the Champion and Ampa fields, according to the Bureau Veritas article. With 214 offshore platforms and over 1,400 wells, the nation’s petroleum infrastructure is extensive, though, it notes. Decommissioning activities are supported by updated guidelines developed in collaboration with Brunei Shell Petroleum.
It is estimated that around 40% of Malaysia’s 300-plus offshore platforms are now over 30 years old — moreover, a significant number are operating beyond their design life. To address this problem, state oil company, Petronas, plans to invest around US$2bn in decommissioning activities over the coming decade. Future plans include plugging and abandoning approximately 153 wells and the abandonment of about 37 offshore facilities, as well as one onshore facility connecting the Sabah-Sarawak Gas Pipeline.
With 450 offshore platforms, Thailand is channelling its decommissioning efforts through initiatives such as Decomm 2.0, the Bureau Veritas article notes, which streamlines regulatory approvals under the Thailand Department of Mineral Fuels. According to Bureau Veritas, the nation’s legal framework, rooted in its Petroleum Act, provides “a strong foundation” for efficient and sustainable decommissioning activities.
ADNOC Drilling Company has announced the award of a US$1.15bn contract from ADNOC Offshore for the provision of two jack-up rigs over a 15-year period, supporting the continued expansion of ADNOC’s offshore operations.
The contract builds on existing agreements and is expected to generate long-term revenue with attractive returns.
With a fleet of 47 offshore rigs, ADNOC Drilling operates one of the largest offshore drilling fleets globally, offering high levels of flexibility and reliability to meet growing demand while maintaining operational excellence and safety standards.
The newly contracted rigs are the latest generation of jack-ups and have been prepared for deployment at the Lamprell shipyard in Sharjah.
The project aligns with ADNOC Drilling’s focus on delivering high-quality solutions while maximising In-Country Value, supporting local partnerships, and advancing the UAE’s economic growth through homegrown innovation.
The rigs will feature advanced digitalisation, AI, and real-time data analytics to enhance safety, efficiency, and operational uptime.
Operations are expected to begin around the end of Q2 2025, with revenue contributions starting in the second half of the year.
The deal reinforces ADNOC Drilling’s medium-term outlook and underpins its strategy for stable, sustainable growth.
Abdulrahman Abdulla Al Seiari, ADNOC Drilling CEO, said, “This new contract is a clear vote of confidence in ADNOC Drilling’s technical leadership, operational excellence and long-term value creation. By integrating artificial intelligence (AI), automation and digitalisation capabilities, the two new jack-up rigs, our newest and most advanced jack-up rigs, will ensure superior efficiency and performance for our client ADNOC Offshore.
"With this contract securing operations until 2040 and beyond, and providing strong, resilient and predictable returns, we are not only reinforcing our role in achieving ADNOC’s production capacity milestones but also driving sustainable long-term growth for our shareholders.”
Tayba Abdul Rahim Al Hashemi, chief executive officer of ADNOC Offshore, said, “In the past month, ADNOC Offshore has awarded long-term contracts worth c. US$3.6bn to ADNOC Drilling to safely accelerate our production capacity growth plans. ADNOC Drilling’s advanced fleet of jack-up and island rigs, market leading integrated drilling services and cutting-edge technologies are critical enablers to deliver ADNOC’s ambitious strategy. This partnership will help us to sustainably meet the world’s growing energy demands and maximise value for shareholders for decades to come.”
Abandoned oil and gas facilities are a significant source of methane emissions, according to the IEA’s recently-released Global Methane Tracker 2025.
IEA analysis suggests that the energy sector was responsible for around 145 Mt of methane emissions in 2024 – more than 35% of the total amount attributable to human activity. Oil operations were responsible for around 45 Mt, natural gas operations for nearly 35 Mt, and abandoned wells for around 3 Mt. An additional 2 Mt of methane leaked from end-use equipment.
Most properly plugged wells emit negligible amounts of methane. But if wells are not properly decommissioned and sealed, they can continue emitting methane for many years, through cracks, fissures and gaps. Most emissions result from wells that have recently been abandoned, which highlights how essential it is to plug and monitor wells that are no longer operational in a timely fashion.
The IEA notes that emissions from abandoned facilities are not given sufficient attention in policies and regulations. It argues that governments can play a critical role, for example by requiring close and decommissioning plans to incorporate measures to mitigate methane emissions. Here, a distinction need to be made between wells for which an operator is accountable and those for which no operator can be identified, ie “orphaned” facilities. In cases where an identified operator is responsible, governments can require operators to perform closure activities for assets being decommissioned, such as plugging and well integrity monitoring. Governments can require operators to set aside funds throughout the asset’s life to finance the decommissioning of abandoned wells.
In the case of orphaned wells, governments can inventory these facilities to identify the main methane emitters. The USA for example has established a programme to identify and inventory orphaned wells on federal lands, which includes measuring and tracking their methane emissions. Western Australia is among those jurisdictions which have undertaken similar inventories. While under the EU Methane Regulation, Member states are required to establish inventories of non-producing wells, identify responsible parties, and take action to mitigate any emissions by August 2025.
To reduce methane emissions from orphaned wells, governments can provide public funding for plugging and sealing. Closure projects could also be made eligible for carbon credits, allowing project operators to trade these credits on carbon markets, the IEA suggests, adding that fees collected from operational assets could help to finance closure activities.
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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