The Qatar BH EPIC EPC (Engineering, Procurement and Construction) project is set to take off as Offshore Oil Engineering Co., Ltd. (COOEC) has kick-started meetings for the project development in Tianjin and Singapore.
This marks the full-scale launch of the largest international offshore oil and gas EPC project contracted by a Chinese company to date. Playing an important role in developing high-quality international oil and gas collaboration under the Belt and Road Initiative, the project will take China-Qatar energy cooperation to new heights.
Situated in the Bul Hanine (BH) oilfield in the Qatari waters of the Persian Gulf, about 100 kms east of the country's coastline, the project will be developed by QatarEnergy with substantial investments. It has a maximum water depth of approximately 40 meters.
Beyond its record-breaking contract value, the project also stands out for its unprecedented scope and technical complexity. It includes more than 60 offshore oil-and-gas facilities, as well as 40 subsea pipelines and cables, and covers the modification of existing platforms and the decommissioning of obsolete facilities.
The full-scale launch of the BH EPIC project will deepen energy cooperation between China and Qatar, and play an important role in advancing energy partnerships among The Belt and Road countries.
DOF Group ASA has secured two new long-term contracts with Brazil’s state-owned energy company Petrobras.
Skandi Chieftain and Skandi Olympia have been awarded four-year charters with the operator, with both contracts offering a combined value of approximately US$200mn. Both vessels will operate with one WROV and are expected to be delivered in October 2026.
The contracts followed the same competitive tender process that resulted in the award of Skandi Achiever, Skandi Carla, Geoholm and Skandi Salvador on the RSV 2024 tender.
Last month the Group was also awarded three service contracts for work in Brazil under Petrobras for subsea inspections as part of the operator’s subsea programme.
The Shah Deniz consortium has recently awarded three significant offshore contracts valued at around US$700mn for the next phase of the Shah Deniz Compression (SDC) project.
These contracts, granted to the Saipem/BOS Shelf joint venture, will play a crucial role in expanding the capabilities of the Shah Deniz gas field, one of the world’s largest offshore gas reserves.
The work covered by the new contracts includes the transportation and installation of a 19,000-tonne compression platform, set to be placed in the Caspian Sea. Additionally, the project will involve the construction and installation of approximately 26 km of offshore pipelines, which will link the new compression facility with existing infrastructure at the Shah Deniz field.
Onshore activities will take place at the Baku Deep Water Jacket Factory, operated by BOS Shelf, while offshore construction will be carried out using two of Azerbaijan’s flagship vessels: the Khankendi subsea construction vessel, owned by the Shah Deniz consortium, and the Israfil Huseynov pipelay barge, owned by Azerbaijan Caspian Shipping Company (ASCO). Both vessels will be operated by Saipem, under the terms of the contracts.
According to Matt Kirkham, BP’s Vice President of Projects for Azerbaijan, Georgia, and Turkey, said, “With the award of these new contracts for major construction and installation works, we are making significant progress on the SDC project. The contracts will fully leverage local fabrication yards and infrastructure, engaging the local workforce. This once again demonstrates that Azerbaijan possesses world-class onshore fabrication and offshore installation capabilities that fully meet international standards. Just one example – between 2026 and 2028, a total of 3,040 tonnes of subsea structures will be fabricated and installed as part of the SDC project. It’s a remarkable piece of activity that highlights the scale and ambition of what we are delivering. I would like to thank everyone who was involved in finalizing these important contracts.”
Offshore work is expected to begin in the third quarter of 2026, with the overall project slated for completion in 2029. This ambitious US$2.9bn project aims to access and produce low-pressure gas reserves, with a target of adding 50 bn cubic metres of gas and 25mn barrels of condensate to the Shah Deniz output.
The new compression facility will be located about 3 km from the existing Shah Deniz Bravo platform in 85 metres of water. Equipped with four 11-MW compressors, the facility will be integral in compressing gas from the Shah Deniz Alpha and Bravo platforms before it is transported to the Sangachal terminal for export.
With construction set to wrap up by 2029, the SDC project will position the Shah Deniz field as a vital player in the global energy market for years to come.
The journey toward large-scale carbon capture and storage (CCS) is gaining momentum, but significant technological and operational challenges continue to slow progress.
According to the CCS Wells Technology Roadmap, a comprehensive report published by the Net Zero Technology Centre (NZTC) in collaboration with DNV and commissioned by the UK’s North Sea Transition Authority (NSTA), key gaps remain in the deployment and optimisation of monitoring technologies essential to ensuring safe, efficient, and long-term CO₂ storage.
The report highlights that while technologies such as Vertical Seismic Profiling (VSP), microseismic monitoring, pulsed neutron logging, and tracer systems are critical to tracking CO₂ movement and storage integrity, each faces its own limitations that must be addressed to unlock the full potential of CCS.
For Vertical Seismic Profiling (VSP), the challenges centre around high operational costs, complex logistics, and limited spatial coverage beyond the wellbore. Although Distributed Acoustic Sensing (DAS) VSP offers enhanced spatial resolution, fibre-optic longevity and signal quality over extended periods, often decades, remain pressing concerns. The report also points out that conducting repeated surveys can be resource-intensive, impacting the long-term sustainability of monitoring programmes.
In microseismic monitoring, the quality of data is often affected by background noise, sensor coupling, and the difficulty of pinpointing small events within deep storage formations. While DAS-based systems can enhance coverage, they still fall short in sensitivity and low-frequency response compared to geophones. Automating the discrimination between injection-induced and natural seismicity, and developing real-time interpretation systems for timely risk response, remain major technological gaps.
When it comes to pulsed neutron logging, the report notes challenges in distinguishing CO₂ in low-porosity or thinly bedded formations. The presence of saline water or complex lithologies can distort results, complicating saturation analysis. Differentiating CO₂ from hydrocarbons, which both exhibit low hydrogen index signals, is also problematic. Achieving accuracy requires robust baseline data, calibration, and the integration of multiple logging methods. As cited by the report, Kim et al. proposed an approach that helps distinguish CO₂ from hydrocarbon gases in depleted gas reservoirs, an important step forward in refining this method.
Meanwhile, tracer technology still faces issues with long-term stability, especially for nanoparticle and biomarker tracers, along with potential cross-contamination and detection challenges in dilute CO₂ plumes. Infrastructure limitations, particularly in offshore or remote sites, compound the issue. The roadmap also highlights the need for improved integration of tracer data with other monitoring results, stronger regulatory frameworks for leakage quantification, and validation of new tracers for environmental safety over extended storage lifespans.
Across all these methods, the NZTC and DNV report underscores a common challenge: scaling field pilots to commercial operations that can run reliably over decades. It calls for more automation, better data integration, and enhanced sensor and tracer durability in CO₂-rich environments.
The information in this article has been extracted from The CCS Wells Technology Roadmap, a report published by the Net Zero Technology Centre (NZTC) and DNV, commissioned by the UK’s North Sea Transition Authority (NSTA). To explore the complete findings and insights, read the full report here.
Navigating the pressures of burgeoning decommissioning liabilities of North America and the Government-flagged urgency for immediate action, Petrofac recently initiated the 'Boomerang' project, mobilising a team to take over custody of the field in only a month.
The company's extensive experience and industry connections allow it to equally leverage the local and global supply chain, thus offering a resonable and customised service with the best suited equipment and crews, in a very tight and competitive market. Such measures helped Petrofac deliver the significant Danos decommissioning project in the Gulf of Mexico by collaborating with more than 250 vendors. It saw Petrofac tackling end-to-end decommissioning services, from project management, planning and engineering to procurement, field execution oversight and fast-tracking mobilisation of industry-leading experts.
To achieve cost efficiency that forms the core of Petrofac's approach to decommissioning, the company resorts to new approaches and innovations to match the project scale.
For instance, deploying compact, low-cost crews for pre-decommissioning activities, involving diagnostic and wellhead maintenance work can ensure better planning, permitting and cost estimating.
Other economic ways employed by the company includes well work delegation to groups of 3-6 people, alongside equipment upgradation, crew utilisation and ensuring minimal non-productive time.
“This significant contract recognises our industry-leading decommissioning programme management experience and our unique in-house capability to manage all well and asset decommissioning phases.
“Four decades of global expertise will be applied to the project, complemented by our already strong onshore presence in Texas,” said Iain Murray, President, Americas, Asset Solutions.
Kuwait Oil Company (KOC), part of Kuwait Petroleum Corporation (KPC), announced the discovery of the Jaza Offshore Gas Field on Monday, which has achieved the highest vertical well output ever recorded from the Minagish formation in Kuwait
This marks a significant milestone following a series of successful maritime exploration ventures, including the discovery of the Al Nokhatha field in July 2024 and the Al Jlaiaa field in January 2025, according to KPC's statement.
Initial tests on the Jaza-1 well have shown impressive production levels, with natural gas output exceeding 29 million standard cubic feet per day (MMSCFD) and condensates exceeding 5,000 barrels per day (BPD). The reservoir stands out due to its low carbon dioxide content, the complete absence of hydrogen sulfide, and the lack of associated water, making it a rare and environmentally significant find in the region.
The initial assessed area of the field spans about 40 square kilometres, with early estimates placing its reserves at around 1 trillion standard cubic feet of gas and over 120 million barrels of condensate. This equates to approximately 350 million barrels of oil equivalent (BOE). KOC noted that these early figures are subject to revision, with further exploration across the field's prospects likely to increase the overall reserves.
ExxonMobil has released a new information document on its Gippsland Basin decommissioning activities, inviting feedback and consultation from stakeholders.
The latest bulletin focuses on Stage 2 of the Gippsland Basin Decommissioning Campaign #1 programme, covering transport, offloading and set-down.
Esso’s planning and preparation to remove non-producing platforms during Decommissioning Campaign #1 is well underway, the document notes.
This includes activities such as the removal of the topsides and supporting steel jacket structures of up to 13 facilities by a heavy-lift vessel (HLV) or construction support vessel (CSV).
The HLV or CSVs will then transport the topsides and steel jackets to a sheltered location closer to shore, within Commonwealth waters (referred to as the transfer area), where they will be transferred onto a heavy transport vessel (HTV) or barge with tugs.
They will then be transported from the transfer area, through existing Corner Inlet shipping channels, before mooring at the Barry Beach Marine Terminal (BBMT) and subsequent offloading and set-down at an Onshore Reception Centre (ORC) within BBMT. Removal, transit and offloading is expected to take around four months.
After set-down at the ORC laydown areas, a dismantling and recycling contractor will dismantle the structures, during which materials will be segregated and sent offsite for recycling or disposal. Dismantling onsite is expected to take between two to three years to complete with a target of recycling over 95% of the material.
The new information bulletin expands on the detailed planning activities and environmental studies currently underway in support of Stage 2, which includes transportation of structures through Victorian State waters and subsequent offload and set-down at the ORC. This is expected to be BBMT, an existing port facility owned by Esso that has been part of South Gippsland’s industrial history for over 50 years and well placed to support decommissioning efforts.
Stage 3 of the decommissioning programme entails the onshore dismantling operations at the ORC.
Stage 1: ORC Early Works (site readiness)
Stage 2: Transportation and offloading operations at the ORC
Stage 3: Onshore dismantling operations at the ORC.
Esso noted that it has received regulatory permissions for Stage 1 from relevant authorities and is now undertaking planning and technical studies for future stages.
Pending regulatory decisions and further public consultation, Stage 2 operations at the ORC are anticipated to commence from September 2027, it added.
This Stage 2 work, including the transportation of structures from the Victorian State waters limit through existing Corner Inlet shipping channels to BBMT via the HTV or barge, will involve approximately 26 marine vessel transits to BBMT, planned between September 2027 and January 2028 (one every five days on average). The HTV or barge will be accompanied by tugs to ensure safe navigation.
Work will also include the offload of structures from the HTV or barge with tugs and set-down within the ORC using self-propelled modular transporters; the refit of structural supports on the HTV or barge with tugs after offloading to prepare for subsequent loads; and short-term storage of structures at the ORC prior to commencement of Stage 3.
Esso also highlighted numerous ways of minimising environmental impacts during the process, notably given the ORC’s proximity to Corner Inlet, an internationally recognised wetland that supports a range of sensitive marine habitats and ecosystems.
Lachlan Harris will replace Sherry Duhe as Santos’ Acting Chief Financial Officer on an interim basis.
Harris has served as Santos’ Treasurer and Deputy Chief Financial Officer for more than two years and has previously acted in the Chief Financial Officer role. Harris joined the company 15 years ago from KPMG and has had extensive experience in a range of risk and finance roles across Santos since.
Managing Director and Chief Executive Officer, Kevin Gallagher, thanked Duhe for her service to the role, “Sherry has made a significant contribution in her time at Santos, leading the structural cost reduction initiative over the past year and implementing a number of other business improvements, particularly in the long-term planning and budget processes.
“Sherry has been a valued member of the Santos executive leadership team and is leaving the company to pursue other interests. I wish her all the very best for the future.”
Ready to be extracted via a single subsea well, Shell's Victory gas field in the UK North Sea will help maintain domestically produced gas for Britain’s homes, businesses and power generation.
Approximately 47 km north-west of the Shetland Islands, the Victory field has started production for Shell UK Limited to reach the Shetland Gas Plant via an existing pipeline network connencted to the subsea well. Utilising the existing infrastructure will reduce operational emissions. The gas will be piped to further travel the Scottish mainland at St Fergus near Peterhead, where it will be fed into the national gas network.
Peak production is estimated at around 150 million standard cubic feet per day of gas (approximately 25,000 barrels of oil equivalent per day) at full capacity, which is equivalent to heat nearly 900,000 homes per year. Most of the field’s recoverable gas is expected to be extracted by the end of the decade.
As older gas fields reach the end of production, Victory can help bridge the gap while also reducing the UK's reliance on imports.
"Gas fields like Victory play a crucial role in the UK’s energy security, and the country will rely on them for decades to come. They provide an essential fuel we need now, and act as a partner to intermittent renewables as we move through the energy transition,” Shell UK Upstream Senior Vice President, Simon Roddy said. “By developing fields like Victory next to existing infrastructure, we are making sure our production in the UK North Sea remains cost competitive and reduces operational emissions.”
Serica Energy plc has announced the signing of an agreement to acquire BP’s entire stake in the P111 and P2544 licences in the UK Central North Sea, pending the waiver of applicable pre-emption rights.
The Proposed Acquisition includes a 32% non-operated interest in the P111 licence, home to the Culzean gas condensate field, and the adjacent P2544 exploration licence.
Culzean, operated by TotalEnergies, is currently the largest single producing gas field in the UK North Sea.
Under the joint operating agreement, the Proposed Acquisition is subject to a 30-day pre-emption period, during which partners TotalEnergies (49.99%) and NEO NEXT (18.01%) may acquire BP’s stake on the same terms. Updates will follow as appropriate.
Chris Cox, Serica's CEO, stated, “Should this transaction complete, it would deliver a step-change for Serica, adding material production and cash flows from the largest producing gas field in the UK. Culzean is a world-class asset, delivering gas from a modern platform with exceptionally high uptime and low emissions.”
The Proposed Acquisition carries an economic date of 1 September 2025, with an upfront cash consideration of US$232mn, subject to customary working capital adjustments and partially offset by interim post-tax cashflows expected by completion at the end of 2025.
Two additional contingent cash payments are included: one linked to successful results from P2544 exploration, and another tied to changes in the UK ring-fence fiscal regime. Funding will come from interim Culzean cashflows and existing financial resources, including the $525 million Reserve Based Lending facility, with the potential for a new acquisition facility to support the Company’s larger asset base.
Culzean is a mid-life gas condensate field discovered in 2008 and onstream since 2019, producing c.25,500 boepd net to BP in H1 2025 at 98% efficiency.
Remaining net 2P reserves are estimated at c.33 mmboe. Production costs are US$10.7/boe, with one of the lowest carbon footprints in the UK North Sea, well below the sector average of 20 kg CO2/boe. Future infill drilling and licensed exploration offer upside potential.
Aceteon’s Moorings and Anchor’s business line, Intermoor, has secured a contract from Petrofac to cover the engineering, mooring equipment, marine spread, installation and removal of a temporary mooring system for the FPSO Northern Endeavour.
The Northern Endeavour permanently shut down in 2019 in the Timor Sea, approximately 550km northwest of Darwin, Australia. Petrofac is managing the decommissioning and disconnection of the vessel.
Under the contract, Aceteon will be responsible for the project management and engineering (PME), design, provision, installation, and recovery of the temporary mooring system, including full mobilisation and demobilisation.
Chee-Hoe Tay, General Manager at Intermoor APAC, said, “We’re proud to leverage our global expertise to support Petrofac on this high-profile decommissioning campaign involving the Australian Government. Our team is fully committed to delivering a safe, seamless execution, and to exceeding expectations through close collaboration, innovation and operational excellence.”
The Northern Endeavour will be positioned offshore Singapore during its decommissioning phase.
Greece is in the final stages of negotiating a major offshore energy exploration contract with US oil major Chevron and local partner Helleniq Energy, aiming to conclude the deal by the end of 2025. The agreement would mark a milestone in Greece’s efforts to boost domestic energy production and strengthen its position as a regional gas transit hub.
Chevron and Helleniq Energy have jointly bid to explore four deep-sea blocks off the Peloponnese peninsula and the island of Crete. “We are working intensively with the US company and Helleniq Energy to meet the timetables and conclude the contract within 2025,” said Energy Minister Stavros Papastavrou on Action24 television.
The initiative aligns with the European Union’s strategy to reduce dependence on Russian gas and enhance energy security following the invasion of Ukraine. Greece, which currently imports most of its gas for power generation and domestic use, hopes the exploration will unlock new reserves and attract long-term investment in its energy sector.
Once signed, the contract will require approval from Greece’s court of auditors and parliament before Chevron begins seismic surveys in 2026. The exploration phase is expected to last up to five years, with any potential test drilling anticipated between 2030 and 2032.
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