Halliburton has introduced the HyperSteer MX directional drill bit, the industry’s first shankless, matrix-body directional bit designed to enhance durability while delivering superior directional control.
Engineered for demanding conditions, the bit enables longer drilling intervals with fewer trips, while withstanding erosion and abrasion in high-flow, abrasive environments.
The launch represents a significant advancement in drilling technology. By integrating the accurate steering capability associated with HyperSteer directional drill bits with the strength of a matrix body, the new design allows operators to drill for extended periods in harsh formations. This supports efforts to reduce overall well time while maintaining high levels of directional performance.
According to Amr Hassan, vice president, Drill Bits and Services at Halliburton, the HyperSteer MX directional drill bits leverage advanced matrix materials to combat erosion and abrasion, prolong bit life in abrasive, high-flow settings, and enhance operational efficiency and reliability.
The bit offers precise directional control across vertical, curve, and lateral sections, helping operators optimize drilling performance while reducing well construction time and costs. By enabling longer runs, the design cuts down on trips, lowers the risk of unplanned events, and preserves directional accuracy even in the most challenging environments.
HyperSteer MX directional drill bits further expand the HyperSteer portfolio and underscore Halliburton’s continued focus on developing engineered solutions that enhance asset value.
Saipem, a global engineering and construction leader, has been awarded two offshore contracts in Saudi Arabia worth a combined US$600mn under its existing Long-Term Agreement with Saudi Aramco.
The first contract, CRPO 162, spans 32 months and covers the engineering, procurement, construction, and installation (EPCI) of around 34 km of 20” and 30” pipelines, along with related works on topside structures at the Berri and Abu Safah oil fields.
The second contract, CRPO 165, runs for 12 months and includes subsea interventions at the Marjan field, as well as the EPC of 300 m of onshore pipeline and associated tie-ins. Saipem said it will deploy its construction vessels already operating in the region to execute the offshore work.
Fabrication for both projects will take place at Saipem’s Saudi facility, Saipem Taqa Al-Rushaid Fabricators Co. Ltd. in Dammam, a move designed to further develop local industry capabilities.
Saipem said the contract awards reinforce its position in Saudi Arabia and strengthen its long-term partnership with Aramco.
This latest project is part of Saipem’s broader strategy to expand its regional footprint, leveraging both local fabrication and offshore expertise to deliver complex oil and gas infrastructure efficiently.
As the year draws to a close, Esso Australia will remember 2025 as a year of several milestones achieved in terms of decommissioning.
Tackling Australia’s largest decommissioning project, the company has completed nearly US$3bn of initial works across offshore operations. This included the permanent sealing of more than 200 wells in Bass Strait, and processing over 10,000 tonnes of steel and concrete for recycling or disposal at Barry Beach Marine Terminal.
The company started out with abandonment activities in the Bream B platform, which was an unstaffed facility. As part of the first phase of a series of high-level decommissioning campaigns, the platform's topsides that formed concrete gravity structures, were removed. The Valaris 107 jack-up rig was deployed to commence plug and abandonment activities across 21 platform-based wells at Bream B. While these activities begun as early as 2024, this year saw the second stage of the plug and abandonment scope.
Other areas of work included end-of-life activities on open water exploration wells and comparatively older wells before moving on to Halibut, which is nearly 60-year old. This work followed extensive inspections on underwater platforms as well as on structural platform above water, including flare booms. Extra-solid steel piled jackets supporting the Halibut platform that needs removal will be around 70-m long, roughly implying the height of a 20-storey building on land.
Work on the Haliburt platform will be followed by decommissioning activities on Esso's first platform, Marlin One.
Other activities completed this year includes abandoning as many as 222 platforms while restoring the original caprocks.
Once Barry Beach work was opened to shareholders for feedback, the company had to rethink its approach and avoid expansion of the port at Barry Beach so as to ensure minimal impact on the Ramsar wetland and onshore environment. Barry Beach is now being equipped with hardstand to accomodate the structures when they arrive.
These activities form a part of solid groundwork by Esso Australia, which will prepare the company before the world’s largest construction vessel, the Allseas Pioneering Spirit, arrives, and will travel from the Netherlands to start removal of 12 retired offshore facilities in 2027.
Gulf Marine Services (GMS) has been awarded a new contract in Europe for two of its Large-class self-propelled, self-elevating support vessels (SESVs), according to World Oil.
The agreement spans 985 days and will see the vessels continue to support offshore operations across the region.
The contract increases GMS’s total contracted backlog to US$540mn, reflecting continued demand for its specialised fleet and offshore support services.
The company operates a total of 13 SESVs, which are capable of platform refurbishment, well intervention, offshore wind support, installation, and decommissioning work.
GMS’s vessels operate across the Middle East, Europe, West Africa, and North America, providing flexible support for both oil and gas and renewable energy projects. The SESVs’ self-propelled and self-elevating capabilities allow them to mobilise efficiently, work in challenging offshore conditions, and perform a wide range of complex tasks for operators in multiple sectors.
The new European contract underscores the strategic importance of GMS’s fleet in supporting long-term offshore operations and highlights opportunities for growth in regions where demand for specialised vessels remains high.
Turkey is planning to finalise an agreement with Syria’s new government on maritime cooperation and offshore exploration and production (E&P), the country’s energy minister said this week.
Speaking to GDH, Energy Minister Alparslan Bayraktar said the deal would allow Turkish oil and gas companies to begin exploring for energy resources off Syria’s coast, with hopes to conclude an agreement sometime next year. The arrangement is expected to build on an existing framework agreement, with results likely emerging further down the line, he added.
Turkey’s state energy firm, TPAO, currently operates two seismic ships and six drillships, including four active vessels – Fatih, Yavuz, Kanuni and Abdülhamid Han – alongside two recently acquired vessels, West Dorado and West Draco, which are slated for restoration. While the company’s recent operations have focused on productive Black Sea wells, Turkey also maintains a strong interest in waters off Northern Cyprus, where disputes with the Nicosia government continue. Drilling in Syrian waters would expand these regional opportunities and strengthen Turkey’s presence in the Eastern Mediterranean. Any future revenues could also provide the Syrian government with additional resources to support economic stabilisation and post-war reconstruction efforts.
The Eastern Mediterranean is widely recognised as one of the world’s most promising regions for offshore natural gas. Recent activity underlines the sector’s potential: this week, Chevron, Shell and NewMed Energy announced plans to begin ordering production equipment for the Aphrodite field in Cypriot waters, which could yield up to 800 million cubic feet of gas per day. A final investment decision on the project is expected in 2027. The development brings Cyprus closer to joining Egypt and Israel in exploiting major regional gas reserves, signalling a new phase in the Eastern Mediterranean’s energy landscape.
The Atlantis Drill Center 1 expansion project turned out a big success for bp as it generated first oil, becoming the major's seventh upstream project startup of the year.
Overall, the platform is equipped to produce up to 200,000 barrels of oil per day. Designed to boost production by an additional 15,000 barrels of oil equivalent per day, the project saw the link-up of two wells to an existing drill center, a subsea hub connecting multiple wells. New wells besides, the subsea tieback also includes existing offshore production facilities through pipelines, managing to keep the 1998-discovered field operational till date, making it bp's longest-running platforms in the Gulf of America.
bp approached the mega-scale project with a sustainable approach that saw the utilisation of existing subsea inventory while drilling and completing wells more efficiently, and streamlining offshore execution planning. This allowed project delivery two months ahead of its original schedule.
"Atlantis Drill Center 1 caps off an excellent year of seven major project start-ups for bp. This project supports our plans to safely grow our upstream business, which includes increasing US production to around 1 million barrels of oil equivalent per day by 2030.
“This latest success demonstrates the dedication of our US project team and our teams around the world, who are delivering new barrels at pace and with lower production costs, in service of growing long-term value for shareholders," said Gordon Birrell, bp’s Executive Vice President of production and operations.
Andy Krieger, bp’s Senior Vice President for the Gulf of America and Canada, said, “This expansion at Atlantis is further testament to the benefits of maximising production from our existing platforms in the Gulf of America, growing bp’s US offshore energy production safely and efficiently.
"We are committed to investing in America as we firmly believe this region will continue to play a critical role in delivering secure and reliable energy to the world today and tomorrow.”
While bp is Atlantis’ operator with 56% working interest, Woodside Energy remains co-owner with 44% working interest.
Buccaneer Energy will be advancing the next phase of development in the Fouke area of the Pine Mills field.
Leveraging the terms of its new offset lease, the company is preparing to implement a secondary recovery (waterflood) based on dedicated injection wells, Turner #1 and Daniel #1. This decision is the result of a technical evaluation of the recently drilled Allar #1 well.
The company is considering the waterflooding approach, as it is known to work especially in the Pine Mills field and surrounding areas. Primary recovery typically ranges between 5% and 20%, of the original oil in place, averaging around 15% in the region. Waterflood promises recovery chances of as much as 30% and 50% of the OOIP. This gives reason to anticipate that recoverable volumes in the Fouke area can go up by two to three times, with current estimates indicating 667,000 to 1,002,000 bbls could ultimately be recovered.
To commence waterflood activities, however, it is necessary to produce before the Texas Railroad Commission the formation of a "waterflood unit" comprising all leaseholders and royalty owners within the proposed area. Potentially, a six-month activity, this will allow to reinstate production from Turner #1, which is expected to deliver a modest contribution to current field output while preparatory engineering and regulatory work progresses.
Paul Welch, Buccaneer Energy's Chief Executive Officer, said, "The decision to initiate a waterflood in the Fouke area marks a key step forward in maximising long-term value from our Pine Mills assets. Waterflooding has a proven track record in these reservoirs, and we believe the Turner #1 and Daniel #1 wells provide ideal injection points to support a highly effective recovery scheme.
We are confident that this programme will materially increase recoverable reserves and enhance the field's production profile. We look forward to updating investors as we progress the regulatory and technical workstreams required for implementation."
An international oil & gas exploration and production company with development and production assets in Texas, Buccaneer owns a 32.5% Working Interest in the Fouke area of the Pine Mills field.
With a special emphasis on production optimisation, Var Energi is advancing a portfolio of early-phase initiatives that include 10 development projects this year.
This initiative covers around 30 high quality projects to attain high value barrels with a production capacity of between 350,000-400,000 barrels of oil equivalent per day (boepd) by 2030 and beyond.
Alongside sanctioning increased oil recovery (IOR) projects and the first phase of Balder Next, the company is looking at a busy line-up of projects ranging from the Previously Produced Fields in the Greater Ekofisk Area (PPF) and Eldfisk North Extension to Mikkel Flow Conditioning Unit (FCU) and Johan Castberg Isflak. Earlier this year, it has also reached final investment decisions (FID) on Balder Phase VI, Fram Sor, Gudrun Low Pressure Project and Snorre Gas Export.
The first phase of the Balder Next project will see the debottlenecking at Jotun FPSO for a boost to production capacity and drilling of new production wells. This will be followed by the decommissioning of the Balder floating production unit (FPU) and development of additional wells.
Nick Walker, CEO of Var Energi, said, "Sanctioning 10 projects this year, up from eight targeted at the start of the year, shows the pace at which we are delivering. We are moving from resources to reserves faster, creating significant value for our shareholders and underpinning our ability to sustain production at 350,000-400,000 boepd towards 2030 and beyond. We have delivered transformational growth this year, the company is de-risked and we have never been in a stronger position. Adding these projects with low-risk, high-returns and short pay-back time, we are strengthening the outlook for delivering long term value."
Backed by strong economics that promises a return of more than 30% and breakeven price of around US$30 per barrel In total, Var Energi's projects are designed to add significant proved plus probable (2P) reserves of around 160 million barrels of oil equivalent (mmboe).
As December 2025 draws to a close, West Africa's offshore oil and gas industry demonstrates steady momentum, driven by conferences, acquisitions, seismic advancements, and ongoing projects amid a challenging market for crude sales.
The MSGBC Oil, Gas & Power Conference, held 8-10 December in Dakar, spotlighted deepwater prospects in the Mauritania-Senegal-Gambia-Guinea-Bissau-Guinea-Conakry basin.
New seismic data highlighted frontier geology, while discussions emphasised LNG progress, green hydrogen, and investment opportunities in onshore/offshore blocks, particularly in The Gambia and Guinea-Conakry.
In Angola, Viridien launched a 4,300 sq km seismic reimaging programme over offshore Block 22 in the Kwanza Basin on 10 December, applying advanced technologies to support upcoming licensing rounds and enhance pre- and post-salt imaging.
BW Energy, in consortium with Maurel & Prom, announced on 12 December the acquisition of a combined 20% non-operated interest (BW's share: 10%) in Blocks 14 and 14K from Azule Energy (BP-Eni JV).
This marks BW's entry into Angola's mature deepwater sector, operated by Chevron, adding immediate production and upside potential.Investor interest persists in deepwater areas across Nigeria, Angola, and Ghana, bolstered by regulatory reforms and gas-focused policies.
ExxonMobil continues its planned US$1.5bn investment to revive Nigeria's Usan field, while Valaris secured a drillship contract for West Africa operations.
However, West African crude faces sales difficulties, with unsold cargoes for December-January loading due to global surplus and competition from cheaper supplies.
Ongoing milestones include the Greater Tortue Ahmeyim LNG project, which achieved first gas earlier in 2025 and is ramping up production.
The sector anticipates 2026 startups and final investment decisions, positioning West Africa for sustained growth despite market headwinds.(Word count: 348)
The Asia-Pacific offshore oil and gas sector advanced significantly in well decommissioning and abandonment during Q4 2025, with key developments in regulatory frameworks, cost assessments, and workforce development amid a projected regional spend of US$30-100bn by 2030 for over 7,000 wells and 1,500 platforms.
Australia took centre stage with the release of its Offshore Resources Decommissioning Roadmap on 9 December.
This government initiative outlines strategies to foster a domestic decommissioning industry, emphasising timely and environmentally responsible removal of infrastructure, workforce training, and international partnerships.
It projects approximately A$60bn in spending over the next 30-50 years, supporting economic opportunities while aligning with net-zero transitions.
Complementing this, a November report by Xodus Group revised Australia's offshore decommissioning liability downward to A$43.6bn (A$66.8bn inflation-adjusted) through 2070, covering over 700 wells, 7,600 km of pipelines, and 520 subsea structures.
The reduction stems from refined forecasting, advancements in well plugging and abandonment (P&A) techniques, and potential efficiencies from coordinated campaigns and emerging technologies.
In Malaysia, Petronas launched the Hydraulic Workover Unit (HWU) Academy on 23 October to address skills shortages in well abandonment.
The academy, a collaboration with industry partners, universities, and government ministries, offers hands-on training using retired assets to build national expertise for safe, cost-effective P&A operations.
This supports Petronas' ongoing plans to plug and abandon around 153 wells and decommission 37 offshore facilities through 2027-2028.
These initiatives underscore the region's focus on cost management, regulatory compliance, and local capacity as Southeast Asia prepares for its decommissioning peak.
Innovations like rigless P&A and rigs-to-reefs are gaining traction to balance economics and environmental stewardship.
As 2025 closes, stakeholders anticipate accelerated activities in 2026, driven by maturing fields and energy transition pressures.
ADNOC has secured US$11bn in structured financing from a consortium of 20 banks to monetise midstream assets linked to its Hail and Ghasha offshore gas project, according to The National.
The Abu Dhabi energy company said it, together with its concession partners Italy’s Eni and Thailand’s PTT Exploration and Production Public Company, opted for a non-recourse financing structure. Under this arrangement, lenders are repaid directly from the project’s future cash flows rather than from the balance sheets of the concession holders.
To enable the transaction, gas processing facilities associated with the Hail and Ghasha concessions were carved out from the upstream project. The financing was reported to be around 1.5 times oversubscribed, reflecting strong interest from regional and international lenders, particularly from Asia.
Hail and Ghasha are among the UAE’s largest offshore gas developments and are expected to produce up to 1.8bn standard cubic feet per day of gas. First gas is anticipated by the end of the decade. A source close to the transaction told The National that the deal was structured as pre-export finance and arranged several years ahead of production.
Chinese lenders, including Industrial and Commercial Bank of China, Agricultural Bank of China and Bank of China, participated in the financing, alongside seven UAE-based banks. The funds will be made available in staggered phases to support construction of gas processing infrastructure, including sulphur separation facilities required for the ultra-sour gas produced from the fields.
Russia’s Lukoil exited its 10% stake in the Hail and Ghasha concession last month, with ADNOC subsequently absorbing the holding. The company said the financing enabled it to secure upfront value at competitive rates while accelerating development plans.
Dr Sultan Al Jaber, Minister of Industry and Advanced Technology and managing director and group chief executive of ADNOC, said Hail and Ghasha would play a central role in the company’s long-term gas strategy and was on track to deliver new gas supplies for customers.
ADNOC added that the financing model could be replicated across other large-scale greenfield projects. Across the region, national oil companies have increasingly turned to monetising midstream assets to unlock capital while retaining ownership. Similar transactions have been completed by Saudi Aramco in recent years, including multibillion-dollar pipeline and gas processing deals with global infrastructure investors.
Offshore oil development plans at Benin’s Sèmè field have suffered a setback after technical complications disrupted drilling operations, forcing a delay to the long-anticipated production start-up.
Akrake Petroleum, a wholly owned subsidiary of Lime Petroleum Holding, which itself is 89.74% owned by Singapore-based Rex International Holding, confirmed that the challenges have pushed first oil beyond the previously targeted timeline.
The issues emerged during drilling at the first of three planned wells at the Sèmè field, located offshore Benin in Block 1. Akrake Petroleum, the field operator, commenced drilling in August 2025 using Borr Drilling’s Gerd jack-up rig, a modern offshore drilling unit supplied by Crystal Offshore Middle East. The campaign was designed to restart production at the mature shallow-water field.
Block 1 spans approximately 551 square kilometres, with water depths ranging between 20 and 30 metres, making it suitable for jack-up rig operations. However, in its latest operational update, Rex International Holding acknowledged that the drilling programme has encountered “further significant technical issues.” While drilling activities are ongoing as teams work to resolve the problems, the company has confirmed that oil production will no longer begin in 2025.
Akrake Petroleum Benin holds a 76% working interest in the Sèmè field and serves as operator, playing a central role in the redevelopment of one of West Africa’s historic offshore oil assets. Prior to the drilling setbacks, key infrastructure milestones had been progressing as planned. The mobile offshore production unit (MOPU) was scheduled for timely delivery, while the floating storage and offloading (FSO) vessel underwent dry docking following a contract awarded in April, both aligned with a Q4 2025 start-up.
The Sèmè field has a long and notable history. Originally discovered by Union Oil in 1969, it was later developed by Norway’s Saga Petroleum. Between 1982 and 1998, the field produced around 22 million barrels of oil before operations were halted amid weak oil prices in the late 1990s.
Despite the current offshore drilling challenges, the Sèmè redevelopment remains a strategically important project for Benin’s energy sector and for Rex International’s African portfolio, as stakeholders look ahead to a revised production timeline.
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