A new report from Fortune Business Insights on the global offshore decommissioning market forecasts that the North America decommissioning market will grow at a CAGR of 7.06% from 2026 to 2034, the highest rate regionally after Europe.
The North America offshore decommissioning market size stood at around US$2.26bn in 2025, accounting for roughly 26.49% of the global market size, valued at US$8.52bn in 2025, according to the report. The region contains over 14,000 inactive offshore wells and more than 2,000 decommissioned platforms, creating a continuous pipeline of abandonment work. Many shallow-water platforms installed in the 1970s–1990s are at the end of their life, while deepwater fields sanctioned in the early 2000s are now entering late-life phases.
Offshore decommissioning is driven mainly by ageing assets, regulatory enforcement, and the economic reprioritisation of offshore portfolios, the report notes. Large energy companies are exiting marginal offshore fields to reallocate capital toward higher-return assets, including LNG, deepwater hubs, and low-carbon investments.
The report highlights the shift from multi-vendor execution toward integrated single-contract (EPC-style) decommissioning models, enableing operators to lock in costs early, transfer execution risk, and simplify regulatory compliance through a single accountable entity. Contractors with combined capabilities, including heavy-lift removal, subsea services, well P&A coordination, and access to certified recycling yards, are gaining a competitive advantage.
Challenges for offshore decommissioning include the high capital intensity combined with cost uncertainty, which continues to delay project sanctioning despite regulatory pressure. Decommissioning expenditures require substantial upfront capital for well plugging and abandonment, heavy-lift vessel mobilisation, subsea clearance, and onshore dismantling. For operators managing multiple late-life assets, these costs compete directly with sustaining capital expenditures (capex) and balance-sheet priorities, often leading to phased or deferred execution rather than complete removal.
One of the most critical challenges is execution complexity arising from legacy infrastructure and incomplete historical data, with many offshore fields scheduled for decommissioning developed before standardised digital asset management and modern integrity documentation came into use. This lack of reliable data increases the risk of encountering unknown well conditions, undocumented tie-ins, or degraded materials during execution.
Offshore decommissioning presents significant opportunities driven by project aggregation, specialisation, and industrialisation of removal activities rather than one-off asset retirement, the report notes. As decommissioning volumes rise sharply in mature basins, operators are increasingly bundling multiple platforms, wells, and subsea assets into multi-field or basin-wide decommissioning programmes. This creates opportunities for contractors to secure long-term framework agreements, enabling fleet optimisation, repeatable execution, and margin stability through scale efficiencies.
Another key opportunity lies in late-life asset transfer and decommissioning-only operators. The report notes that financial investors and specialist firms are acquiring end-of-life offshore assets specifically to execute decommissioning at lower cost through lean operating models and optimised contracting strategies, opening the market for advisory, engineering, and execution partners with specialised decommissioning expertise rather than traditional exploration and production (E&P) capabilities.
The products and services provider for offshore developments has secured a multi-year contract worth seven figures with a global offshore services company to support intervention and abandonment activities offshore Spain.
Under the agreement Aquaterra will deliver a subsea well access solution across 11 wells. The campaign will be executed from a semi-submersible vessel, where Aquaterra will supply a 7-3/8” ID, 5,000 psi rated intervention riser system. The complete riser-based solution will integrate with the customer’s subsea pressure control system to enable efficient intervention and abandonment activities.
Aquaterra Energy CEO, George Morrison, said, “Securing this multi-year contract is a significant milestone for Aquaterra Energy. Well intervention and abandonment is increasingly the defining challenge for many mature offshore basins and we have invested in building the team, capability and technology required to make these campaigns a success as our customers navigate complex late-life field operations.”
Ben Cannell, Innovation Director at Aquaterra, commented, “Well access to support intervention and abandonment remains a key focus for us as we continue to expand our capability and presence in this market. This project is a strong example of collaboration in action, bringing together our riser-based well access solution and OEM AQC-CW connector technology to deliver a practical, integrated system that supports safe, efficient and reliable offshore operations throughout complex abandonment campaigns.”
According to Westwood, plug and abandonment is expected to account for almost half of total decommissioning expenditure in the UK North Sea, with similar pressures of ageing assets moving into the abandonment phase being witnessed in Spain.
The integrated subsurface, wells and facilities specialist has acquired Applied Petroleum Technology AS (APT), a geoscience company in a move which strengthens Elemental’s existing subsurface capabilities.
APT provides basin modelling and subsurface analysis to support well exploration, production and plug and abandonment decisions. The acquisition helps Elemental create an integrated team spanning geoscience, reservoir engineering, geochemistry and petroleum engineering.
The acquisition meets rising demand for deeper subsurface insights, with APT’s laboratory-based geochemical analysis adding a critical layer of subsurface insight to Elemental’s offering alongside traditional geoscience and reservoir engineering workflows.
APT will also bring established digital tools to Elemental’s portfolio, including Girasol which is used for wellsite gas interpretation and P&A decision-making.
Mike Adams, CEO of Elemental Energies, said, “As subsurface decisions become more complex across mature assets, decommissioning and CCS, we are continuing to invest in specialist capabilities that help our clients make more informed decisions. Bringing APT into Elemental Energies expands out subsurface and geochemistry expertise, creates new opportunities for our teams and strengthens our ability to support clients at every stage of the asset life cycle.”
Helge Nyrønning, CEO of APT, commented, “APT has always focused on delivering high-quality geochemical insight to support critical subsurface decisions. Becoming part of Elemental Energies is an exciting next step for our business and our people. It gives us the scale, reach and multidisciplinary environment to grow our capabilities, work more closely with clients we already know well, and apply our geochemistry expertise within fully integrated subsurface and wells team, particularly form our strong base in Norway.”
AF Offshore Decom has signed a contract with Ithaca Energy for decommissioning work in the UK sector of the North Sea
The contract scope includes the engineering receipt, cleaning, dismantling and recycling of a FSU weighing approximately 24,000 metric tons.
Lars Myhre Hjelmeset, EVP Offshore at AF Gruppen, said, “We are very pleased to have been awarded a second major contract by Ithaca Energy following the award of the FPF-1 asset in December 2025. As a result of the awards, AF Environmental Base Vats will receive close to 50,000 tons of floating production and storage facilities from Ithaca energy in 2026.
“The two units will, after initial preparations, be loaded onto our yard in a combined gloat over and load in operation, consistent with earlier similar projects at AFEBV. The units will be cleaned, dismantled and thereafter the steel will be repurposed, upcycled and recycled creating several circular material solutions for the agriculture, construction and civil industries in the Nordic region.”
The contract has been valued in the range of NOK350-400mn (approximately US$36-41mn).
Aker Solutions has secured a five-year framework agreement to provide maintenance, modification, and operations (MMO) services in the Yggdrasil area, with options to extend for up to two additional four-year periods from 1 March 2026. The work will form part of the next-generation MMO alliance covering Valhall, Fenris, Ula, EIGA (Edvard Grieg and Ivar Aasen), Skarv, Alvheim, and Yggdrasil.
The alliance aims to set new benchmarks in project execution and delivery, embracing advanced technology and AI-driven methods to boost productivity, reduce costs, and shorten project lead times. Greater organisational integration and a performance-focused commercial model are central to the approach.
Kjetel Digre, Chief Executive Officer at Aker Solutions, said: “This contract marks a new chapter for Aker Solutions. We are proud to serve as the MMO provider for the Yggdrasil Area, including three topsides, Hugin A, Hugin B, and Munin. It is an area that will set a new benchmark for remote operations and low-manned and unmanned production platforms.”
The agreement includes a significant share of local deliveries, supporting Norwegian industry through engineering and project management in Stavanger, Sandnessjøen, and Mumbai, and fabrication at Aker Solutions’ yards in Egersund and Sandnessjøen. Offshore employees will also benefit from the programme.
The award will be recorded as order intake in the Life Cycle segment in the first quarter of 2026, reflecting expected work during the five-year fixed period.
Malaysia’s Vantris Energy continues its corporate transformation after rebranding from Sapura Energy in 2025 with work on projects in support of the country’s offshore sector.
Its indirect wholly-owned subsidiary, Sapura Offshore Sdn Bhd, has been awarded work orders for offshore transportation and installation (T&I) services in Malaysia by Petronas Carigali Sdn Bhd.
The awards comprise the provision of T&I services for offshore facilities at the Sepat Integrated Redevelopment Project and the Belud South Greenfield Development Project.
Work on both is set to commence early this year by the group’s engineering and construction (E&C) arm, with Belud South anticipated for completion by the end of 2027, and Sepat by the third quarter of 2029.
The company said in a statement that it also marked a “strategic shift” towards opportunities with lower-risk contracting models.
“These contracts demonstrate Vantris Energy’s offshore T&I capabilities, and our continued focus to deliver sustainable performance across our core businesses, prioritising opportunities aligned with our capabilities, regional strengths, and risk appetite,” said Vantris Energy CEO Muhammad Zamri Jusoh.
With a stronger balance sheet following its restructuring in late 2025, the company is keen to strengthen its business across all areas of operation.
Vantris Energy is also active in numerous other areas, including oil well intervention and decommissioning.
The company also last month announced the divestment of its 40% equity interest in L&T-Sapura Shipping Pvt. Ltd., which owns and operates the LTS3000 heavy-lift and pipelay vessel.
The company sold up to its joint-venture partner, Larsen & Toubro Limited (L&T), in a deal valued at US$30.5mn, consisting of equity consideration and the full repayment of the outstanding shareholder’s loan and accrued interests owed to the group.
It marked another step in Vantris Energy’s ongoing efforts to streamline, strengthen and optimise its asset portfolio, according to Jusoh.
The outlook for well support, interventions and other associated services across West Africa should be buoyed by the prospect of high levels of wildcat drilling this year.
According to analysis by Rystad Energy, the global upstream sector is set to carry strong momentum into 2026, with high-impact drilling activity expected to remain elevated following a solid 2025.
Africa is set to continue leading global activity, it estimates, accounting for around 40% of planned high-impact exploration wells, driven largely along the Atlantic margin, with exploration expected to focus on the Orange Basin in southern Africa and the Gulf of Guinea in West Africa, reinforcing the region’s role in global high-impact drilling.
Wells are designated as high-impact based on a variety of factors: the size of the potential resources, whether they could open new hydrocarbon plays in frontier or emerging basins, and their significance to the operator.
Such activity in 2026 is expected to drive exploration momentum higher in specific basins and countries, with 42 such wells identified globally — close to half of them in Africa.
Last year, the success rate for high-impact wildcat wells rose to 38% from 23% in 2024, while total discovered volumes increased by 53% year on year to around 2.3 billion barrels of oil equivalent (boe), according to Rystad Energy.
What we are seeing in 2026 is a clear shift in which where operators are willing to deploy capital, according to Aatisha Mahajan, Rystad Energy’s Head of Exploration, Oil & Gas Research.
“Ultra-deepwater and frontier plays remain capital-intensive, but they also offer scale and material upside at a time when conventional opportunities are increasingly limited,” Mahajan said.
“Africa stands out because it still combines geological potential with the prospect of large, commercially meaningful discoveries, particularly for operators looking to secure long-life resources in a tightening global supply environment.”
Of around 17 potential high-impact wells across Africa during 2026, nearly all are offshore, with just a few onshore.
The continent scores twice as many proposed wells as Asia, the next busiest region, followed by South America and Europe.
Subsea pipelines used by the oil and gas industry may contain naturally occurring radioactive materials, mercury, hydrocarbons, and heavy metals that pose a risk to human health and the environment, a parliamentary inquiry into decommissioning offshore oil and gas infrastructure has heard.
Appearing before the Legislative Council Environment and Planning Committee’s inquiry into decommissioning oil and gas infrastructure, Fern Cadman, Fossil Fuel Industry Campaigner at the Wilderness Society warned that Gippsland’s offshore region has around 800 km of subsea pipelines.
“Even if buried, eventually they will degrade, and all that is going to end up in the environment,” she told the Committee.
Stan Woodhouse from environmental organisation Friends of the Earth told the hearing that some contaminants can bioaccumulate and move through the food chain.
“If we leave it on the seabed, it will end up on our dinner plates,” he said.
The Committee is investigating the scale and legal ownership structure of the infrastructure, including offshore wells, pipelines, high-pressure transmission and low-pressure distribution systems and relevant projects in Commonwealth waters.
The environmental groups advocated for removing the pipelines before they have a chance to corrode.
“Industry says it’s too hard to remove them, but engineers say almost anything can be done, you just have to be prepared to pay for it and use the right tools,” Cadman added.
Instead, Victoria should treat the pipelines and other infrastructure as a potential resource and an opportunity to boost domestic steel recycling and cut emissions.
Jerusha Beresford, Sustainability Adviser at the Australian Steel Institute (ASI), urged the Committee to recognise the value of infrastructure such as oil platforms that have reached the end of their life.
“We are strongly recommending that the scrap steel recovered from the decommissioning of the Bass Strait oil and gas infrastructure is recognised as a valuable national resource and prioritised for local recycling into domestic steel manufacturing and not exported,” Beresford told the Committee.
According to ASI, the first tranche of decommissioning will yield 60,000 tonnes of high-grade steel from 12 retired platforms, with significantly more expected over the next decade.
“Demand for steel for renewable infrastructure alone is forecasted to be about 400,000 tonnes per year through to 2030…retaining scrap locally is essential to meet that demand,” he added.
The benefits extend beyond supply security. Using scrap steel in manufacturing dramatically reduces carbon intensity compared to primary production and can support Australia’s transition to low-emission steelmaking.
Beresford told the hearing that both electric arc furnaces and blast furnaces rely heavily on scrap, with the former using up to 90% recycled content.
Economic modelling also points to strong local gains.
ASI cited analysis showing that every 10,000 tonnes of scrap steel that’s processed domestically creates 37 jobs and $4.8mn in value-add, compared to just $1.3mn if exported.
“Scrap use lowers the carbon intensity of steelmaking by reducing reliance on primary resources like iron and coal…It is crucial in meeting Australia’s capability to manufacture low-emission steel products,” Beresford said.
However, he warned that without regulatory intervention, contractors may opt to export scrap for short-term financial gain.
“Unfortunately, the past has showed that sometimes scrap is exported because it is perceived to be an easier way to get rid of the waste and the contractor gets paid for it,” he added.
With Australia’s steel industry employing 100,000 people and generating $30bn annually, Beresford said the decommissioning pipeline represented a ‘once-in-a-generation' chance to strengthen domestic manufacturing, create jobs and advance the circular economy.
Jumbo Offshore has completed mooring pre-installation activities for the FPSO Errea Wittu at Uaru field, Stabroek block, offshore Guyana for Exxon Mobil Guyana
The scope of work, conducted on behalf of Modec, included the installation of suction anchors and the pre-lay of mooring lines in preparation for FPSO hook-up.
Jumbo Offshore performed installation engineering, procurement, mobilisation and marshalling activities to support offshore installation, using Jumbo Offshore’s J-class installation vessel, Fairplayer.
“I am very proud of the hard work and commitment shown by all Jumbo personnel and subcontractors during the preparation, mobilisation, and execution of this deepwater pre-lay mooring project,” said Freek Muurling, Project Manager at Jumbo Offshore. “The team demonstrated full focus on engineering, procurement, documentation, and meticulous planning in sometimes challenging circumstances. The yard and offshore teams’ resilience and teamwork led to a safe and successful completion of the mooring line installation campaign."
Muurling also highlighted the effective communications between Jumbo, Modec, and Exxon, which created a strong working relationship and contributed greatly to moving the project forward safely and efficiently.
The Uaru field is located 200 kilometres offshore Guyana at a depth of 1,750 metres and is estimated to hold more than 800 million barrels of oil. Production is expected to begin this year.
The Errea Wittu FPSO will produce 250,000 barrels of oil per day and will have a gas treatment capacity of 540 million cubic feet per day. It will have a water injection capacity of 350,000bpd, a produced water capacity of 300,000bpd and a storage capacity of two million barrels of crude oil.
Guyana is seeing its offshore sector expand rapidly, which in turn is spurring significant economic growth in the country. According to Finance Minister Ashni Singh Singh, whose remarks when presenting the nationa's annual budget were reported by Reuters, the oil sector is set to grow 17.9% this year. He forecast 309 crude oil cargo exports, up from 260 last year, and estimated oil revenue of about US$2.79bn.
ExxonMobil Guyana Limited and its Stabroek block co-partners, Hess Guyana Exploration Limited, and CNOOC Petroleum Guyana Limited are progressing several offshore developments in Guyana’s offshore Stabroek Block. The consortium reached a new production milestone of 900,000 bopd in November 2025, following the ramp-up of Yellowtail, Guyana’s fourth offshore project, and excellent operating performance from other assets. Once its other four planned developments are in production, ExxonMobil Guyana expects to have total production capacity of 1.7mn bopd.
The Asia-Pacific offshore decommissioning market is steadily gaining importance within the wider global offshore decommissioning industry.
Although the region still lags behind North America and Europe in terms of total market value, it is expected to record strong growth over the coming years. This expansion is being driven by aging offshore oil and gas infrastructure, evolving regulatory frameworks, and rising environmental concerns, all of which are pushing operators and governments to prioritise end of life asset management.
Market research indicates that the APAC offshore decommissioning market in 2024 was valued at around US$1.5bn, with expectations that it will grow to more than US$3.5bn by 2035 at a CAGR approaching 7.8 % from 2025 to 2035. Major offshore producing nations including China, India, Japan, South Korea, Malaysia, Thailand, and Indonesia are playing a central role in this expansion. According to GM Insights, the Asia-Pacific market alone is forecast to grow at a CAGR of over 6 % through 2034, supported by the ageing of offshore assets and stronger regulatory oversight.
China currently holds the largest share of the regional market, supported by strict environmental standards and a significant number of ageing offshore installations. India is also emerging as a strong growth market, driven by supportive policies and shifts in national energy strategies. Meanwhile, Japan and South Korea are placing greater emphasis on advanced technologies and safety focused decommissioning methods, while countries such as Malaysia, Thailand, and Indonesia continue to develop their decommissioning capabilities as offshore fields mature.
Technological progress including robotics and remotely operated vessels, along with closer collaboration between stakeholders, is helping to reduce costs and address logistical challenges. Despite hurdles such as high execution costs and regulatory complexity, increasing environmental scrutiny and scheduled asset retirements position the APAC offshore decommissioning sector as a key growth area through 2035, creating long term opportunities for service providers and technology innovators.
Halliburton has introduced the XTR CS injection system, a wireline-retrievable safety valve engineered for CO₂ injection in carbon capture, utilization, and storage (CCUS) wells.
The system offers flexibility, serving as a primary or backup safety valve or as a deep-set reservoir fluid-flowback prevention device. Unlike conventional surface-controlled wireline valves, the XTR CS injection system’s non-elastomeric design reduces leak paths and removes dependence on hydraulic operation systems. Its performance remains consistent at any depth, simplifying operations and inventory management.
The XTR CS injection system further strengthens Halliburton’s Completion Tools leadership in low-carbon technology solutions, enabling operators to optimize CCUS well performance. The system supports safe and efficient CO₂ injection, even in challenging environments.
Maxime Coffin, vice president, Halliburton Completion Tools, said, “The CS designation is a testament to Halliburton’s technology capabilities. The rigorous CS qualification program ensures the system’s operational integrity and survival capabilities in harsh CCUS environments.”
The system can be customized for specific injection media and fluid properties, delivering low opening force, minimal pressure drop, and a broad range of injection rates. To prolong operational life, high-velocity flow is directed away from seal areas, while a novel anti-throttle feature reduces valve wear, maximizing reliability.
“With the XTR CS injection system, Halliburton provides an adaptable solution to help operators achieve reliable CO₂ injection performance and advance their carbon management goals,” Coffin added.
Syria has taken a significant step towards reviving its energy sector after signing a landmark agreement to develop its first offshore oil and gas field.
The memorandum of understanding was signed this week between the Syrian Petroleum Company, US energy major Chevron, and Qatar based Power International Holding.
The signing took place in Damascus and was attended by senior officials, including the US special envoy to Syria, Tom Barrack. According to Syria’s state news agency SANA, the agreement focuses on offshore exploration and the development of oil and gas resources within Syria’s territorial waters. It also aims to encourage wider investment and long term growth across the country’s energy sector.
The deal marks Syria’s first formal move into offshore energy exploration and reflects the government’s efforts to attract foreign partners and rebuild hydrocarbon production after years of decline. Youssef Kabalawi, CEO of the Syrian Petroleum Company, said, “Before the summer, God willing, we will start mobilization and drilling.”
He added that reaching the gas reserves could take up to four years, underlining the long term nature of the project.
Syria’s oil and gas industry has suffered severely due to nearly fifteen years of conflict, which resulted in widespread damage and the loss of hundreds of thousands of lives. Before unrest began in 2011, oil production stood at around 380,000 barrels per day, with exports generating more than $3 billion in 2010. At that time, oil revenues made up roughly a quarter of the government’s budget.
Recent developments may improve the outlook. Syrian government forces regained control of large areas in the north east and oil rich eastern regions last month, potentially opening the door to renewed exploration in some of the country’s most valuable energy zones.
Since coming to power in December 2024 after the removal of Bashar Assad, Syria’s new authorities have prioritised economic recovery. The offshore agreement with Chevron and Power International Holding signals a clear intention to rebuild the energy sector and re establish Syria as a regional player in oil and gas development.
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