In its Annual Report for 2025, Australia's Santos outlines its structured approach to decommissioning, with a focus on best practice in environmental management, safety and community engagement, and plans that address its decommissioning obligations, including regulatory and sustainability requirements.
In 2025, the company embedded the Decommissioning Project Process and Technical standards throughout its regional business units, for safe and efficient project delivery.
Attention is focused on decommissioning right from the outset, and continues throughout the project lifecycle, with decommissioning strategy and cost estimates defined as part of project investment decision. The decommissioning strategy, plan and cost estimates are updated regularly throughout the asset production phase and incorporated into operation and maintenance plans and budgets. The decommissioning plan addresses regulatory requirements, joint venture agreements, timing constraints, cost estimates, opportunities and risks.
Ten years prior to the cessation of production, opportunities are explored for asset repurposing, divestment or field life extension. With a focus on the repurposing of assets towards CCUS and other decarbonisation opportunities as part of the company’s commitment to sustainability and responsible asset management, Santos seeks to identify alternative uses for wells, infrastructure pipeline and facilities which have reached the end of their operational life, and actively assesses reservoirs and wells for their suitability for long-term CO2 storage. (For example it has repurposed reservoirs to support CO2 storage for the Moomba CCS project). It also looks at repurposing pipelines and processing facilities for new energy projects, such as transporting low carbon fuels.
Five years prior to production cessation, the company initiates the decommissioning process and develops a decommissioning plan.
After the cessation of production, decommissioning projects are executed following due processes and in accordance with regulatory requirements, with a focus on minimising environmental impact, restoring ecosystems or adapting them for reuse, and addressing residual environmental risks through post-decommissioning monitoring and mitigation. Platform, pipelines, subsea infrastructure and other facilities are decommissioned according to the approved environmental plan (EP).
Santos stresses its commitment to engaging local communities and stakeholders in decommissioning planning and activities, keeping them informed and involved, to enable transparency and social licence to operate, as well as to facilitate the management and mitigation of potential impacts.
The company also plays an active role in shaping industry-wide decommissioning practices, and influencing the future of decommissioning in Australia.
In its Annual Report, Santos also provides an update on specific decommissioning projects, including the safe decommissioning of wells in the Mutineer-Exeter-Fletcher-Finucane well decommissioning campaign, including the recycling of waste materials; the successful disconnection and recycling of the Ningaloo Vision FPSO in the Van Gogh-Coniston-Novara field; preparatory works for the removal of Harriet Alpha platform; support to non-operated joint ventures; and progress of decommissioning in the Cooper Basin.
Global energy technology group SLB, through its OneSubsea joint venture, has been hired for more work on Malaysia’s first deepwater field, which has now been in production for almost 20 years.
It highlights the growing role of specialist technology and support, including well and intervention services, as the country’s offshore sector matures.
In this latest project, SLB OneSubsea has been awarded an engineering, procurement and construction (EPC) contract by PTTEP Sabah Oil Limited, for various services on the Kikeh field, the country’s first deepwater oil and gas development, which started producing since 2007 — when the first subsea tree manufactured by SLB OneSubsea in Malaysia was deployed.
PTTEP Sabah Oil Limited is a subsidiary company of PTT Exploration and Production Public Company Limited (PTTEP).
“Building on our long-standing collaboration with PTTEP, this award supports the next phase of the development of Malaysia’s deepwater resources,” said Mads Hjelmeland, CEO of SLB OneSubsea.
“With more than two decades of experience supporting PTTEP’s subsea projects, our team is well positioned to deliver safe, efficient and integrated execution across all three recent contract awards.”
The contract expands SLB OneSubsea's role in delivering integrated subsea production systems (SPS) for PTTEP's deepwater portfolio offshore Malaysia and marks the third major SPS award from PTTEP in the last 12 months.
As part of the EPC contract, SLB OneSubsea will deliver comprehensive SPS equipment for the second development of the Kikeh 3B project, including three subsea trees, a manifold, a subsea distribution unit and integrated control systems, along with project management and associated services.
Project execution will run through 2026 and 2027, supported by SLB OneSubsea's manufacturing and services facilities in Malaysia.
“Today, SLB OneSubsea continues to work alongside PTTEP to expand production, at water depths of 1,300-1,400 metres, while increasing local manufacturing of high-value subsea equipment and systems, strengthening local supply chains and building expertise and capabilities in the region,” the company noted in a statement.
Following a period of challenging drilling work, including horizontal wells, Lime Petroleum has confirmed that the hook-up of its Mobile Offshore Production Unit (MOPU) and Floating Storage and Offloading unit (FSO) has been completed on the Sèmè field in Benin.
After the FSO Kristina was anchored in place, a flow-line was laid from the Stella Energy 1 MOPU to the FSO.
“Commissioning of the production system is well underway, with oil now flowing into the FSO,” a Lime Petroleum statement noted on 5 March, 2026.
Over the coming days, further testing and commissioning will take place, with the aim to optimise production rates and start regular production, it added.
However, drilling operations proved a challenge, the company reported earlier in February.
While the latest operational milestones marked an important step forward, it noted that drilling operations “encountered significant technical complications” — this resulted in a “material increase in drilling costs and a production delay of more than three months.”
The delays and complications brought with them knock-on financial implications, it added.
At the field, it follows the drilling of the AK-2H production well by Lime Petroleum’s wholly-owned indirect subsidiary Akrake Petroleum Benin.
A total of 1,405 metres was drilled horizontally through the reservoir section at the site.
The well was geo-steered using advanced Logging While Drilling (LWD) tools to ensure the well only encountered oil-bearing reservoir sandstone.
The Sèmè Field, discovered by Union Oil in 1969, is located in Benin’s Block 1in shallow water depth of 20 to 30 metres.
It was first developed by Norwegian oil company, Saga Petroleum, and had produced approximately 22 MMbbl1 between 1982 and 1998, before production was stopped prematurely due to low oil prices of around US$14 per barrel in 1998.
A consortium of TotalEnergies with Shell and Repsol, has started producing oil at the Lapa South-West project, a new development in the Lapa field, located in the Santos Basin, approximately 300 km offshore Brazil.
The Lapa South-West project will increase production from the Lapa field by 25,000 bpd, bringing the field’s total production to around 60,000 bpd. The development of the project consists of the subsea tie-back of three wells to the Lapa Floating Production, Storage and Offloading (FPSO) unit, enabling the development of additional reserves while leveraging the available capacity of the existing Lapa FPSO.
TotalEnergies (operator) holds 48% working interest in the project, with Repsol Sinopec Brazil and Shell holding 25% and 27%, respectively.
The project represents a significant addition to the portfolios of all three companies.
“The start-up of our operated Lapa South-West project marks another important milestone for TotalEnergies in Brazil, a key growth country for our company,” said Nicolas Terraz, President Exploration & Production of TotalEnergies. “This project, which leverages the available capacity of the existing Lapa facilities, delivers low cost and low emission oil production in line with our company strategy and contributes to the achievement of our objective to grow our production by 3% per year until 2030”.
TotalEnergies has been operating in Brazil for 50 years and employs around 4,000 people in the country. Its Exploration & Production portfolio currently includes nine licenses, of which four are operated. In 2025, the company’s average production in the country was 184,500 barrels of oil equivalent per day. This start-up represents a ramping up of TotalEnergies’ portfolio in Brazil, following the start-up of Mero-4 in May 2025, and ahead of the start-ups of Atapu-2 and Sépia-2 expected in 2029.
“The start-up of Lapa Southwest is another example of our strong track record of efficient delivery on the key projects where we have taken FID in recent years. This enables us to continue high-grading our upstream portfolio,” added José Carlos Vicente Bravo, Executive Director of International E&P at Repsol.
Repsol Sinopec, is a joint venture formed by Repsol (60%) and Sinopec (40%) is today the one of the largest oil and gas exploration and production companies in Brazil with a strong portfolio focused on offshore pre-salt assets, including producing fields such as Albacora Leste, Lapa, and Sapinhoá, and growth projects such as Raia. It was the first private company to participate in the opening of the Brazilian pre-salt exploration market, and has invested significantly in the country over the past decade
Shell, meanwhile, is the second largest oil and gas producer in Brazil after Petrobras, with investments including the Gato do Mato, a deep-water project in the pre-salt area of the Santos Basin, offshore Brazil for which it took FID last year, as well as the Atapu and Mero pre-salt projects, also in the Santos Basin. Shell is committed to growing its high margin portfolio in Brazil, viewing its assets in the country as among the most competitive in its global portfolio.
ExxonMobil has provided a round up of its 2025 decommissioning activities off Australia’s Bass Strait, as well as plans for 2026.
Andy Hospodar, Senior Project Manager Australia Major Projects at Esso Australia Resources Pty Ltd, summarised the company’s current position in the ExxonMobil Decommissioning Progress Report 2025.
It includes a busy programme ahead for the coming year across key offshore assets.
“Esso is progressing the safe shutdown and decommissioning of the non-producing Bass Strait facilities in consultation with stakeholders,” said Hospodar.
“At the same time, Esso continues to safely operate offshore platforms and subsea facilities that still produce energy for the region.”
Esso Australia Resources owns and operates the following assets in Bass Strait: 421 wells; 19 platforms; six subsea facilities; and more than 800 kilometres of subsea pipeline.
These assets form part of the Gippsland Basin Joint Venture between Esso and Woodside Energy (Bass Strait) Pty Ltd (Woodside Energy) and the Kipper Unit Joint Venture (Esso, Woodside Energy, and Mitsui E&P Australia Pty Ltd).
Building on the momentum of 2024, Hospodar said that during 2025 Esso completed all well abandonments across all GD 817 listed wells, advanced facility preparation across multiple platforms and strengthened regulatory alignment through proactive Safety Case submissions and approvals.
“Decommissioning activities remain on track to meet key milestones,” he noted in the report, highlighting close engagement with official bodies such as the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA).
More Safety Cases are expected to be submitted to NOPSEMA in early 2026, he added, including flushing activities and Stasis Mode transition of Fortescue, and a combined MPSV campaign and transition to Stasis Mode for Flounder, Mackerel and Kingfish A.
“Development of the combined Safety Case covering future MPSV campaigns and transition to Stasis Mode for Bream A is [also] ongoing with completion targeted for the first quarter of 2026,” noted Hospodar in the report.
The group’s forward planning timeline for decommissioning actives in the area stretches into the 2030s, with work spread across multiple fields.
KOIL Energy Solutions Inc. has secured a major contract from an international oil company to support an offshore development project in West Africa, reinforcing its role in delivering specialised services for deepwater energy projects
The company will provide load out, transit oversight, installation monitoring and pre-commissioning services as part of the development. The contract covers a comprehensive range of activities, including engineering support, project management, offshore and onshore personnel, as well as specialised rental equipment required for subsea operations.
As part of the project, KOIL Energy will deploy its personnel and equipment to transportation and installation vessels, as well as to quayside locations and offshore production facilities. The work will involve supporting the installation and pre-commissioning of several subsea umbilical systems that will connect to an existing deepwater production field.
Mobilisation for the project is expected to begin during the second half of 2026.
"This contract is a recognition of our company’s capabilities of delivering mission-critical services to deepwater developments internationally," said Erik Wiik, CEO of KOIL Energy. "It is also a testament to our teams’ expertise in testing of advanced deepwater systems and helping customers bring production online efficiently and safely."
KOIL Energy is widely recognised for delivering subsea systems and services that support offshore oil and gas projects throughout their lifecycle. The company’s specialised testing equipment and operational methodologies are designed to help operators accelerate project timelines and move more quickly toward production.
Founded in 1997 and headquartered in Houston, KOIL Energy provides engineering expertise, subsea equipment and technical support services to energy and offshore industry clients worldwide. Its team of engineers and manufacturing specialists focuses on developing solutions for complex subsea challenges while supporting energy projects across global offshore markets.
ASX-listed Bhagwan Marine Limited has stepped up its position to support Australia’s offshore industries, including involvement in the decommissioning effort, with the acquisition of rival firm Riverside Marine.
The Australian marine solutions company announced the acquisition recently, unveiling the transaction terms on a debt-free cash free basis with a normal level of working capital, for an enterprise value of up to US$130mn.
“This significant acquisition represents a step-change in scale and scope for Bhagwan, strengthening the company’s position as a preferred marine solutions partner,” it stated in a release to the ASX.
Founded in Brisbane in 1926 by the Campbell family, Riverside specialises in the management and operation of approximately 30 diverse vessels, including nine owned vessels, across five established brands.
The Riverside group has long-standing clients within the industrial resources, scientific research, transport and logistics sectors.
Riverside is forecasting FY26 revenue of $63mn and EBITDA of US$26mn, the ASX statement added.
Announcing the strategic rationale behind the deal, Bhagwan Marine cited a strong alignment and highly complementary service offerings.
“The acquisition brings together two founder-led businesses with a strong strategic fit, complementary services and a commitment to operational excellence,” a Bhagwan Marine media statement added.
The acquisition also further diversifies Bhagwan Marine’s offer across services, including third-party vessel operations, harbour tugs, sand dredging and commercial ferries, and across commodities, including iron ore, metallurgical coal and industrial sand.
It also boosts geographic spread with an established presence in North Queensland, and additional operations in Mackay and the Pilbara.
Bhagwan Marine added that the deal increases its recurring revenue base from around 40% to around 50%, supported by long-term contracts and high barriers to entry.
The company recently christened its newest vessel, 'Bhagwan Micah' at its Brisbane operational base, which could play a key role in the nation’s decommissioning drive, highlighting that it is purpose-built for the energy transition and critical infrastructure sectors.
Energy services company Expro has introduced Solus, a new high debris single shear and seal ball valve system designed to improve flexibility, safety, and efficiency in subsea well access operations across the global oil and gas sector.
The newly developed system replaces the conventional requirement of two separate valves with a single integrated valve. By simplifying the design, Solus reduces operational complexity and risk while supporting the industry’s move toward more efficient and cost effective subsea intervention technologies.
Solus has been tested and validated according to API Std 17G and is fully compliant with NACE MR0175 standards. It is designed as a fail close bi directional ball valve that can shear and seal on wire and coiled tubing, even in environments with significant debris. This capability marks an important development for subsea safety and reliability.
The system can be used in both riser and open water applications and is suitable throughout the entire well lifecycle. This includes exploration, appraisal, completion intervention, and later stage activities such as plug and abandonment and full decommissioning.
Solus has already been deployed in several operations. It has been used for an in riser completions development in the Gulf of America and installed in an open water system for a North Sea plug and abandonment campaign. The valve can provide shear and post shear sealing for both gas and liquid on slickline, braided electrical cable, and coiled tubing. It also maintains bi directional sealing capability even after pump through operations.
The technology has also been incorporated into Expro’s lightweight Plug and Abandonment Open Water Intervention Riser System. By achieving shear and seal functions within a single valve, the design enables Solus to operate effectively in open water environments.
Its modular structure allows isolation and disconnection from the well, while the compact configuration aligns with the industry’s transition toward smaller blowout preventer stacks. This also supports more efficient supply chain management and easier deployment.
The fail close design helps reduce emissions risk and provides an additional independent well safety barrier. Solus also offers strong high debris tolerance, with qualification for solids ingress of up to 15 percent.
Daniel More, Vice President Subsea Well Access, said, “In introducing Solus, Expro now offers the subsea engineering market a distinctive new system that provides the ultimate integrated shear and seal on coiled tubing and wire using just a single valve. Solus, cuts through operational complexity. Simple to use, flexible, with a compact design for smaller BOP stack sizes, this is the latest in fail-safe technology developed by the experts of valve technology and systems integration.
“When there’s no room for error, Solus is designed to provide the assurance of an independent well safety barrier, combined with the surety and confidence that comes from Expro’s integration experience and expertise at the ‘whole system’ level. It’s the latest example of Expro’s engineering excellence and deep understanding of customer needs to move our industry forward,” added Daniel.
Solus is available within Expro’s ELSA landing string assemblies portfolio. It can be deployed in riser as a single valve, with an optional latch mechanism, as part of a subsea test tree, or integrated within the Open Water Intervention Riser System.
Equinor has completed its investigation into a well control incident on the Deepsea Bollsta drilling rig that resulted in a gas release during operations in September 2025.
The company confirmed that the incident, which occurred on 23 September while plugging a well at the Troll Field, has been classified in its most serious internal category of severity.
According to the investigation report, the event happened while crews were cutting a 13-3/8-inch casing at a depth of around 510 metres. During the operation, gas and fluid escaped from the well and spread across the drill floor and into the shaker room, an area where rock fragments and drill cuttings are separated from drilling fluids before the fluid is circulated back into the well.
One worker experienced difficulty leaving the room because of pressure differences caused by the release. The individual managed to exit using force but suffered minor injuries and received first aid on board the rig. The escaping gas and fluid also caused damage to the ventilation system in the room’s ceiling.
Despite the seriousness of the event, company officials said multiple safety barriers operated as intended. Automatic gas detection systems activated emergency protocols, which included shutting down potential ignition sources across the rig.
Crew members then activated the rig’s blowout preventer and diverter system in line with emergency procedures. The diverter redirected gas, fluids and pressure away from the installation before the blowout preventer fully closed.
The system sealed the well after approximately 71 seconds, stopping the flow of gas. Operators reported that the situation was brought under control within about half an hour.
Calculations carried out during the investigation estimate that roughly 930 kilograms of gas were released over a short period. The volume triggered a “Red 1” classification within the company’s internal risk management framework, indicating the highest level of severity.
The investigation found that the blowout preventer remained open at the moment the casing was cut, while gas had accumulated behind the casing in a confined space. Equipment used to log the annulus area behind the casing had not been correctly calibrated, meaning the trapped gas was not detected before the operation began.
Officials stressed that the gas was contained in a limited volume behind the casing and was not connected to the reservoir, meaning the incident did not present a risk of an uncontrolled blowout.
Following the event, the company introduced new procedures requiring the blowout preventer to be closed when cutting shallow casings or pulling casing strings, regardless of activation timing.
Rune Nedregaard, senior vice president for drilling and well operations, said the findings would be shared with industry partners and suppliers, while the investigation by the Norwegian Ocean Industry Authority would also inform further safety improvements.
As part of its measures to advance responsible offshore energy development, the Bureau of Ocean Energy Management has published the Final Programmatic Environmental Impact Statement for Gulf of America Regional OCS Oil and Gas Lease Sales and Post-Lease Activities.
It comes with a solid environmental review framework with a robust and transparent environmental evaluations for future exploration, development, and decommissioning activities in the Gulf. This development has also been supported by bodies such as the United States Government Accountability Office, which had expressed the need for clearly defined timelines, when it comes to decommissioning.
It had pushed for better enforcement of decommissioning deadlines in a safe manner on BOEM's part, ensuring thorough execution of the actions planned. GAO's proposals came on the basis of extensive reviewing of laws, regulations, implementing guidance, policies, procedures, budget justifications, and other documentation related to the bureau's decommissioning deadlines.
It had pointed out the urgency of addressing long-standing issues such as effectiveness of enforcement tools, deadlines delivery, supplemental bonding levels and operational standards.
On the status of bonding coverage for decommissioning liabilities, GAO proposed on adopting a reporting mechanism or additional direction laying out how BOEM can balance the priorities set by the Outer Continental Shelf Lands Act, including safety, environmental protection, development of resources, conservation of resources. This will help to promptly address the risks pertaining to decommissioning liabilities, enabling timely decisions on future mitigation measures.
Australia’s Woodside spent almost US$1bn on decommissioning activities around the globe last year, the company reported in an update recently.
“In 2025, Woodside continued execution of planned decommissioning activities spending approximately US$823mn across our portfolio.”
In Australia, it cited “significant progress” across the Enfield, Griffin and Stybarrow fields, offshore north west Western Australia, as well as the Minerva field, offshore Victoria.
Outside Australia, decommissioning is ongoing with work in Canada, at both the upstream Liard and Horn River basins and downstream Kitimat locations in British Columbia, and in the USA where one deepwater well has been plugged and abandoned and legacy site decommissioning is ongoing.
“Our priority as we conduct decommissioning work is the safety of our people and the environment,” the statement posted on its website added.
“We conduct this work using recovery methods developed by Woodside and our specialist contractors, who bring experience, technical know-how and specialist equipment required for the variety of activities in our decommissioning portfolio.”
Within Australia, work included the conclusion of the 10-well Stybarrow plugging campaign that commenced in 2024), the retrieval of the Echo Yodel umbilical and the completion of plugging and abandonment activities at the Minerva field.
“In 2025, final infrastructure was recovered from the Enfield field, concluding a multi-year decommissioning programme that included permanently plugging and abandoning all 18 Enfield wells, recovering and deconstructing the Nganhurra riser turret mooring, and removing flexible flowlines, umbilicals and other subsea structures,” the company stated.
“Deconstruction of the Nganhurra riser turret mooring reused, repurposed or recycled 99.6% of materials. Enfield is the first project that Woodside has taken from exploration through development and operations, to decommissioning. The remaining activity at Enfield is to complete final surveys, which are planned for 2026.”
The Gippsland Basin Joint Venture (GBJV), comprising Esso Australia and Woodside also continues planned decommissioning activities in the Bass Strait.
In 2025, 69 wells were plugged and abandoned, contributing to a cumulative total of more than 220 wells permanently plugged since the campaign commenced.
This includes the completion of plugging the Bream B and Kingfish A platform wells in the first half of 2025.
Woodside added that detailed engineering and execution planning, including submission of environmental approvals to regulators for assessment, is “well advanced” for the Bass Strait offshore platform removal campaign planned to commence in 2027.
Velesto Energy Berhad has kicked off 2026 on a strong note, securing a long term drilling contract from PETRONAS Carigali Sdn. Bhd. for its NAGA 2 jack-up rig. The deal spans a firm period of five years, with operations already underway as of February 2026 and expected to run through to 2030.
For a company that operates in one of the more demanding corners of the energy sector, this kind of contract is no small thing. A five year commitment from one of the region's most prominent operators signals genuine confidence in Velesto's capabilities and track record. It also gives the Group something that every drilling company values deeply — visibility. Knowing where your assets will be deployed, and for how long, makes planning far more straightforward and keeps revenue streams steady even when market conditions shift.
Megat Zariman Abdul Rahim, President of Velesto, said, "The award marks an important milestone for Velesto and an excellent start to 2026. The five-year engagement for NAGA 2 reflects our continued progress in maximising the utilisation of our core assets while strengthening earnings visibility. We appreciate the trust placed in Velesto and remain committed to delivering safe operations and consistent performance throughout the contract period."
The rig at the heart of this contract is no ordinary piece of kit. NAGA 2 is an independent leg cantilever jack-up drilling rig built to handle serious operational demands. It carries a drilling depth capability of 30,000 feet and is rated for operating water depths of up to 350 feet, making it well suited for the offshore environments found across Malaysia and the broader Southeast Asian region.
This latest award fits neatly into Velesto's wider strategy of disciplined asset management and focused execution across its core operating markets. With NAGA 2 now firmly committed for the next five years, the Group looks to be in a solid position heading into the rest of the decade.
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