Buccaneer Energy that operates exploration and production activities in Texas, United States, has completed an organic oil recovery pilot project in its Pine Mills field in East Texas.
One injector and two of four producing wells in the Northern section of Pine Mills (Battery 3 area) were subjected to treatment, resulting to a 100% production boost. To facilitate the process of organic oil recovery, a nutrient mixture was injected into the reservoir to stimulate the growth of naturally occurring microorganisms. The rapid growth of these microbes converts the surface properties from hydrophilic (attracted to water) to hydrophobic (repelled by water). This leads to better mobility of residual oil within mature waterflood systems, as the microbial action reduce the interfacial tension between the rock face and the reservoir oil. One treated producer experienced a significant reduction in water cut immediately following treatment.
The post-treatment period has not only recorded an increase from 15 bopd to approximately 30 bopd but maintained consistency. Water cut was nil from 80% in one of the treated wells.
With costs akin to any routine field workover, the company is currently planning follow-up treatment of the remaining two producing wells.
The company will continue to evaluate production performance at the treated wells while also designing the next phase of field implementation.
Paul Welch, Buccaneer Energy's Chief Executive Officer, said, "We are very encouraged by the success of the Pilot Project where average production from the area treated increased 100% to 30 bopd. The initial results significantly exceeded our expectations. The process is well-suited to mature waterfloods, like Pine Mills, where the "easier oil" has been produced and a large amount of residual oil remains in place. Efficiently dislodging this residual oil has a significant impact on production rates. One of the treated producers in the Pilot went from an 80% water cut to a 0% water cut after treatment, a remarkable result.
"Most importantly, the cost of this treatment is modest and comparable to a routine workover, meaning it can be applied without a material capital investment.
"As highlighted in our recent reserve update, Pine Mills carries an NPV10 of approximately $9.6 million at $60 oil pricing. Our current market capitalisation is approximately £1.3 million. Our focus is on closing that gap through incremental production growth, improved recovery and disciplined execution. We see this programme as a practical step toward converting underlying reserve value into cash flow and look forward to updating shareholders as we expand the initiative across the field."
PT Pertamina has signed a memorandum of understanding (MOU) with global drilling giant Halliburton to accelerate the deployment of advanced well construction and stimulation technologies in Indonesia.
Under the MOU, the two companies will evaluate opportunities for various advanced well services, Halliburton reported in a media statement.
This will include: multi-stage hydraulic fracturing, acid stimulation, advanced cementing services, as well as the potential application of closed-loop automation and artificial intelligence capabilities to improve drilling and fracturing performance in selected onshore fields.
According to Simon A. Mantiri, president director of PT Pertamina, the collaboration forms an integral part of the Indonesian state energy firm’s sustainable transformation of upstream production, increasing national lifting and ensuring reliable energy supply.
“With the support of advanced technology and global expertise, we are confident that mature fields can be revitalised and optimised to unlock their full potential, enabling the fields to, once again, be productive and contribute to national energy production,” he said.
Martin White, senior vice president, Asia Pacific, Halliburton, said his team brings global experience to local field operations to improve stimulation effectiveness and optimise production.
“Halliburton integrates proven unconventional methodologies with localised reservoir insights to improve performance, strengthen local capabilities, and deliver technology-based solutions that maximise asset value for our customers,” he noted.
“The MoU also expands Halliburton’s unconventional completions footprint in Indonesia and emphasises how the company’s collaborative approach maximises asset value.”
Saipem has strengthened its position in the Middle East after securing a new offshore contract in Saudi Arabia valued at approximately US$500mn.
The award comes in the form of a Contract Release Purchase Order under the company’s existing Long Term Agreement with Saudi Aramco.
The project centres on the Safaniya oil field, recognised as one of the largest offshore oil fields in the world. Under the agreement, Saipem will carry out the Engineering, Procurement, Construction and Installation of a 48 inch trunkline stretching around 65 kilometres offshore and a further 12 kilometres onshore. The development will also include associated subsea facilities designed to support ongoing production and long term field performance.
Offshore activities will be handled by Saipem’s construction vessels that are already operating in the region, ensuring continuity and operational efficiency. Meanwhile, fabrication work will take place at Saipem Taqa Al Rushaid Fabricators Co. Ltd. in Dammam. This local yard continues to play a key role in strengthening the company’s industrial presence within the Kingdom and supporting domestic capability.
The Safaniya field remains central to Saudi Arabia’s energy infrastructure, and this latest contract reflects the Kingdom’s ongoing investment in maintaining and enhancing offshore production capacity. By combining local expertise with established engineering knowledge, Saipem aims to deliver a project that meets strict safety, quality and environmental standards.
This award not only expands Saipem’s project portfolio in Saudi Arabia but also deepens its longstanding relationship with Aramco. Over the years, the company has built a strong track record in delivering complex offshore developments across the region.
With construction set to move forward using both regional assets and technical experience, Saipem continues to demonstrate its ability to execute large scale offshore projects efficiently while supporting the broader development of strategic energy infrastructure in Saudi Arabia.
A Victorian parliamentary inquiry has heard warnings that ageing subsea pipelines in Bass Strait could leach hazardous contaminants into the marine environment, while also presenting a major opportunity for domestic steel recycling.
Witnesses appearing before the Legislative Council Environment and Planning Committee’s inquiry into decommissioning oil and gas infrastructure highlighted serious concerns over the legacy pollution from offshore facilities in Victoria’s Gippsland region.
Fern Cadman, Fossil Fuel Industry Campaigner at the Wilderness Society, told the committee that around 800 km of subsea pipelines in the Gippsland offshore area contain naturally occurring radioactive materials, mercury, hydrocarbons, and heavy metals.
These substances pose risks to human health and the environment.
“Even if buried, eventually they will degrade, and all that is going to end up in the environment,” Cadman said.
Stan Woodhouse from Friends of the Earth echoed these fears, noting that contaminants can bioaccumulate and transfer through the food chain.
“If we leave it on the seabed, it will end up on our dinner plates,” he said.
The groups urged full removal of the pipelines before corrosion advances, rejecting industry claims that removal is too difficult.
Cadman countered, “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.”
The committee is examining the scale, legal ownership, and structure of Victoria’s oil and gas infrastructure, including offshore wells, pipelines, high-pressure transmission systems, low-pressure distribution networks, and projects in Commonwealth waters.
In contrast, Jerusha Beresford, Sustainability Adviser at the Australian Steel Institute (ASI), presented decommissioning as a strategic resource for Australia’s circular economy.
The first phase of Bass Strait platform retirements is expected to yield 60,000 tonnes of high-grade steel from 12 platforms, with much more anticipated over the coming decade.
Beresford called for prioritising local recycling into domestic steel manufacturing rather than export.
“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,” he told the committee.
Demand for steel in renewable infrastructure is projected at about 400,000 tonnes annually through to 2030, making retained scrap essential.
Recycling scrap dramatically cuts carbon intensity compared with primary production from iron ore and coal, supporting low-emission steelmaking via electric arc furnaces (up to 90% recycled content) or enhanced blast furnace processes.
Economic benefits are substantial: every 10,000 tonnes processed locally generates 37 jobs and AUD$4.8mn in value-add, versus just AUD$1.3mn if exported.
Without regulation, contractors may export scrap for short-term profit, as past patterns suggest.
Beresford described the moment as a “once-in-a-generation” chance to bolster manufacturing, create employment, and advance sustainability in an industry employing 100,000 people and generating AUD$30bn yearly.
The committee’s report is due by June 2026.
VAALCO Energy has announced encouraging operational advancements in its West African assets, highlighting successful drilling results in Gabon and confirmation of its operatorship in a key discovery offshore Côte d’Ivoire.
In Gabon, the company has successfully drilled, completed, and brought online the Etame 15H-ST development well within the Etame field’s 1V block.
The well encountered a 250 m lateral section of net pay in high-quality Gamba sands positioned near the reservoir top.
It has achieved a stabilised flow rate of approximately 2,000 gross barrels of oil per day (BOPD), with a 38% water cut, produced through a 42/64 choke and an electrical submersible pump (ESP) operating at 54 Hz.
This performance aligns closely with expectations derived from the earlier ET-15P pilot well.
VAALCO is actively managing the well to stabilise reservoir pressure and optimise long-term output.
The drilling rig has remained on the Etame platform, and in mid-February, it spudded a step-out exploration well targeting the West Etame (ET-14P) prospect.
This well, drilled from the S1 slot, carries a 57% chance of geological success and is anticipated to reach the target zone by mid-March.
Should it prove successful, the prospect could deliver significant additions to production and reserves by the end of 2026.
Turning to Côte d’Ivoire, VAALCO has been formally confirmed as operator of the Kossipo field on the offshore CI-40 block, holding a 60% working interest, with partner PetroCI retaining 40%.
The Kossipo field, originally discovered in 2002 by the Kossipo-1X well and appraised in 2019 by Kossipo-2A (which tested at over 7,000 BOPD), lies southwest of the producing Baobab field.
Recent ocean bottom node (OBN) seismic data has enhanced and de-risked VAALCO’s updated evaluation and development strategy.Independent estimates indicate gross 2C contingent resources of approximately 102 million barrels of oil equivalent (MMBOE), with around 293 MMBOE in place.
The company anticipates completing a field development plan during the second half of 2026.
Additionally, the Baobab Ivorien FPSO (formerly MV10), currently positioned off the east coast of Africa, is expected to return to Côte d’Ivoire waters by late March, supporting resumed operations and future drilling on the block.
These updates underscore VAALCO’s focus on organic growth through targeted drilling and field development in its core African portfolio.
The company expressed optimism about enhancing production profiles and reserves in both regions
Mubadala Energy has completed the acquisition of a 15% participating interest in the Nargis Offshore Area concession from Eni, strengthening its footprint in Egypt’s offshore gas sector.
The Nargis concession is an offshore exploration block located in the Mediterranean Sea and is considered a high-potential asset within the East Nile Delta Basin.
The transaction marks a further expansion of Mubadala Energy’s portfolio in Egypt and underlines its strategy of investing in core gas-producing regions.
Following the deal, Eni retains a 30% contractor interest in the concession through its subsidiary, IEOC.
The block is operated by Chevron, which holds a 45% contractor interest, while Tharwa Petroleum Company owns the remaining 10% stake.
The concession operates under a partnership structure with the Egyptian Natural Gas Holding Company (EGAS), with the contractor group and EGAS each holding a 50% interest.
Mansoor Mohammed Al Hamed, managing director and chief executive of Mubadala Energy, said the acquisition reinforces the company’s long-term commitment to Egypt and broadens its exposure to what he described as a high-impact growth opportunity in the strategically significant Eastern Mediterranean region.
“The acquisition of a 15% interest in the Nargis Concession further reinforces our long-term commitment to Egypt, expanding our portfolio with a high-impact growth opportunity alongside world-class partners in the strategically important East Med region,” he said.
The Nargis block lies approximately 50 km offshore in the prolific East Nile Delta Basin and includes the Nargis-1 discovery, which was made in early 2023.
The find has attracted industry attention as part of wider exploration success in the Mediterranean waters offshore Egypt.
The concession is adjacent to the Nour block, also operated by Eni, in which Mubadala Energy acquired a 20% stake in 2018.
In addition to its interests in Nargis and Nour, Mubadala Energy holds a 10% stake in the Shorouk concession, which is home to the producing Zohr gas field, also operated by Eni.
The latest acquisition further consolidates Mubadala Energy’s position in Egypt’s offshore gas landscape, aligning with its broader strategy to expand its international gas portfolio and support long-term energy supply from established basins in the Eastern Mediterranean.
Chevron and HELLENiQ ENERGY have signed a landmark agreement with the Hellenic Republic granting exploration rights to four major offshore blocks, opening one of the largest unexplored maritime areas in the European Union to potential natural gas development.
Under the agreement, Chevron will hold a 70% stake and act as operator, while HELLENiQ ENERGY will retain the remaining 30%. The blocks are located south of Crete and the Peloponnese and cover a combined area of approximately 47,000 sq km.
The move is seen as a significant step in Europe’s ongoing efforts to diversify energy supplies and reduce reliance on Russian gas, which still accounts for roughly one-fifth of the EU’s imports. By unlocking new exploration acreage in the Eastern Mediterranean, Greece is positioning itself as a potential contributor to future regional gas supply.
The joint venture partners confirmed that the exploration programme will proceed in phases, beginning with seismic surveys scheduled to commence later this year. The initial data acquisition will help assess the hydrocarbon potential of the largely untapped offshore area before any drilling decisions are made.
Speaking at the signing ceremony in Athens, Prime Minister Kyriakos Mitsotakis described the agreement as a strategic development for both Greece and the wider European energy market. He noted that the European Union’s decision to curb dependence on Russian gas had created new opportunities for member states to strengthen domestic and regional energy production.
Mitsotakis highlighted Greece’s ambition to enhance its role as a regional energy hub, citing existing and planned infrastructure projects that connect South-Eastern Europe with broader European gas networks. He emphasised that, despite the EU’s long-term climate goals and transition towards renewable energy, natural gas would remain an essential component of Europe’s energy mix for years to come.
Industry observers view the agreement as a potential catalyst for further exploration activity in Greek waters, which have historically been underexplored compared with other parts of the Mediterranean. The size of the concession area makes it one of the most significant offshore licensing arrangements within the EU in recent years.
For Chevron, the deal strengthens its presence in the Eastern Mediterranean, while HELLENiQ ENERGY consolidates its role in domestic upstream development. The success of the initial seismic phase will be critical in determining whether the region can deliver commercially viable gas resources capable of contributing to Europe’s long-term energy security.
Eni has announced a major oil discovery following the successful drilling of the Algaita-01 exploration well in Block 15/06 offshore Angola.
The well is located approximately 18 km from the Olombendo FPSO, with preliminary assessments indicating oil in place of around 500 million barrels.
Drilling operations began on 10 January 2026 using the Saipem 12000 drillship in water depths of 667 metres. The well intersected multiple oil-bearing sandstone intervals within Upper Miocene formations. These reservoirs have been described as having strong petrophysical characteristics, supporting their commercial potential. An extensive data gathering programme, including fluid sampling, confirmed both reservoir quality and favourable fluid properties.
The proximity of established production facilities, including the Olombendo floating production, storage and offloading unit, strengthens the economic case for development. Access to nearby infrastructure is expected to shorten development timelines and optimise capital expenditure, improving the overall viability of bringing the resource on stream.
Block 15/06 is operated by Azule Energy, which holds a 36.84% interest, in partnership with SSI (26.32%) and Sonangol E&P (36.84%). Azule Energy is jointly owned by Eni and bp, and the latest find further reinforces the consortium’s upstream position in Angola.
The discovery highlights the continued exploration potential of Angola’s offshore basins, particularly within mature producing blocks where near-field opportunities can deliver material additions to reserves. By leveraging existing infrastructure and technical expertise, operators are increasingly able to unlock value from adjacent prospects while maintaining cost discipline.
Looking ahead, appraisal activities will likely focus on refining reserve estimates, evaluating development concepts and assessing tie-back options to current facilities. If progressed efficiently, the Algaita-01 discovery could contribute meaningfully to Angola’s medium-term production outlook, supporting national revenue generation and strengthening the country’s role as a key hydrocarbon producer in sub-Saharan Africa.
Asia Pacific is preparing for a steady year of high impact exploration in 2026, with around 10 to 12 significant wells expected across the region.
While global exploration remains measured, activity here reflects a careful balance between ambition and financial discipline. Operators are focusing on frontier areas with the potential to unlock sizeable new plays, particularly in deep water settings.
Offshore Papua New Guinea, attention centres on the long anticipated Mailu prospect. This well is expected to test a frontier deep water carbonate play that could open a new chapter for exploration in the area. In Malaysia, deep water activity will also gather pace. The Jampuk and Langka prospects are both set to probe carbonate systems that remain lightly explored but technically promising.
Indonesia is likely to see renewed frontier drilling. Petronas may spud Akbar 1 in the Bobara production sharing contract in eastern Indonesia. If it proceeds, the well will bring an end to a twelve year pause in frontier deep water drilling in that region. At the same time, Eni continues its exploration efforts in the Kutei Basin, where it is drilling the large Miocene fan prospect known as Geliga. Success there could strengthen confidence in the wider basin.
In India, ONGC and Oil India are due to wrap up their frontier campaigns in the Andaman and Kerala Konkan basins in early 2026. The next phase of high impact drilling could then shift towards deeper waters, led by Vedanta Cairn India in the Krishna Godavari basin block KG DWHP 2017 1.
Australia is also expected to re enter the exploration scene. Santos is planning a return to drilling in the Roebuck Basin from late 2026, targeting potential Triassic plays at Curie and Ara. This marks a long awaited step back into frontier activity for the company.
Overall, Asia Pacific’s 2026 drilling programme signals cautious optimism, with several wells capable of reshaping the region’s exploration landscape.
Perenco Congo has installed the new Kombi 2 platform with connection work currently underway on the Kombi-Likalala-Libondo II (KLL II) field, before commissioning begins early March.
This marks the first redevelopment move in more than 20 years since the drilling of its last well.
The field's future performance will stand secured from Kombi 2's new-generation infrastructure that ensures improved water and effluent treatment and increased associated gas recovery. On top of that, two gas turbines will generate 8 MW of electricity for greater energy autonomy for operations.
Designed to meet global sustainability standards, the six-well drilling campaign starting this year will involve production optimisation, enhanced field recovery, and field-life extension work, all of which will be supported by the forward-looking Kombi 2 platform.
Considering it a historic field, Perenco Congo has invested more than US$200mn with a long-term strategy in the region. “This project is a concrete example of Perenco's commitment to investing in high-performance, responsible, and value-creating infrastructure that promotes the sustainable development of national resources,” said Gregoire de Courcelles, managing director of Perenco Congo.
Recfishwest, a non-profit organisation representing the interests of Western Australian recreational fishers, and global energy company Woodside have collaborated to install the Dampier Artificial Reef.
The Dampier Artificial Reef is a new, pupose-built artificial reef designed to boost recreational fishing opportunities and enhance marine biodiversity off the Western Australian coast. Backed by scientific research and community input, it has the support of the WA Government, City of Karratha, Traditional Owners and fishing clubs. It aims to create a new marine habitat and boost recreational fishing opportunities in the Pilbara region. The reef consists of 48 purpose-built concrete modules installed in approximately 35 metres of water, near Rosemary Island in the Dampier Archipelago, Western Australia. Each module is designed with complex internal spaces and hard surfaces to encourage coral growth, shelter juvenile fish and attract larger species higher up the food chain, creating a thriving and sustainable marine ecosystem. The 48 concrete reef modules were installed on the seabed from Fugro’s multipurpose vessel, the Fugro Etive.
Over time, the site is expected to become a high-quality fishing location for species such as Spanish mackerel, cobia, emperor, cod and even sailfish – a welcome addition for local fishers and visiting anglers alike, while supporting local tourism. Similar projects, such as Exmouth’s King Reef, have transformed bare sand into vibrant habitats supporting more than 150 fish species within five years.
Recfishwest CEO Dr Andrew Rowland said, “The deployment of the Dampier Artificial Reef will provide new fishing opportunities while enhancing fish habitats. Our collaboration with Woodside demonstrates what can be achieved when industry and the recreational fishing community work together for positive outcomes.
“These scientifically designed structures build healthier oceans — supporting biodiversity, boosting fish stocks and strengthening ecosystem resilience. Most importantly, they create fantastic new fishing opportunities particularly in this instance for pelagic species like mackerel and sailfish, and all the flow-on benefits that brings to coastal communities,” he said.
Woodside acting executive vice president & chief operating officer Australia Breyden Lonnie said, "Woodside is excited to collaborate with Recfishwest and the local fishing community to bring this new reef to life. The reef is expected to provide a productive marine habitat for diverse species of algae and corals, supporting an abundance of fish life to feed and shelter. Not only is the reef expected to contribute to marine biodiversity; it will also be an added drawcard to boost fishing tourism to the Pilbara, supporting the local economy and communities."
The installation of the reef was funded by Woodside and its Scarborough Joint Venture partners JERA Australia and LNG Japan. Woodside’s joint venture partner in the Enfield Joint Venture, Mitsui E&P Australia, contributed to the acquisition of the concrete modules for the reef.
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.
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