Issue 92 Innovation + Technology_48pp-ISSUU

Unlocking the power of subsurface data: Optimising workflows in Petrel

Welcome to the May edition of ‘OGV Energy Magazine’ where this month we are exploring the theme of Innovation & Technology. With the OGV team heading out to Houston for OTC and to All Energy in Glasgow we're excited to see how the full energy supply chain is utilising these new advances to improve both their performance and their profitability!

A big thank you to our front cover partner 3T this month, you can read all about how they are using state of the art simulators and virtual reality to create authentic yet risk free training scenarios.

We are also delighted to welcome contributions from Cegal, Draeger, Rotech, Intervention Rentals, GDI, Vulcan and Moblyze

The rest of this month’s magazine, as always, provides you with a review of the Energy sector in the North Sea, Europe, Norway, Middle East, Australia and the US, along with industry analysis and project update

Warm regards, Dan Hyland

As the energy sector undergoes one of the most significant transformations in its history, driven by digitalisation and shifting global demands, the need for highly skilled, safetyconscious professionals has never been greater and 3t is meeting these challenges head-on.

At its heart, 3t is a leading safetycritical training and learning business for hazardous and highly regulated environments. It blends decades of industry expertise with deeply embedded technology, enabling it to go far beyond classroom instruction. Using high-fidelity simulation, real-time data feedback, and cloud-based platforms, 3t creates learning experiences that are not only immersive and scalable but tailored to the real-world pressures of energy operations.

Powering Progress: How 3t is Using Technology to Build Safer, Smarter and More Resilient Workforces

3t offers a full spectrum of expertise across training and learning offered across five distinct service lines, each purposefully created to deliver a tailored solution to its global client base:

• 3t Training Services – Accredited, hands-on instruction at 10 global safety-critical training centres

• 3t Drilling Systems – Industry-leading drilling and well control simulation technology

• 3t Digital – Scalable eLearning, VR, and cloud-based training management platforms

• 3t Workforce Solutions – Tailored global workforce and skills development programmes

• 3t Managed Services – Fully outsourced training and competence workforce management support

3t’s deep-rooted commitment to technology that not just supports training, but transforms it, is what truly sets the company apart from its competition.

3t’s ability to offer a blended solution across its service lines is a specialism that elevates outcomes exponentially – enhancing learning outcomes and engagement, as well as driving tangible commercial results for clients. 3t is redefining how the energy sector prepares for real-world challenges, bringing precision and realism to the forefront of training – in turn ensuring a safe, competent, highly engaged workforce.

Ground-breaking simulation. Real world impact.

Drilling operations are complex, highstakes environments where failure is not an option, as mistakes can have costly, even catastrophic consequences. That’s why simulated learning is the game-changer of safe, effective workforce development across the global energy sector.

3t Drilling Systems helps its global client base to reimagine traditional training with cuttingedge simulators that replicate real-world scenarios with astonishing accuracy. The world-leader in advanced simulation solutions for over three decades, they’ve built and deployed more than 1,600 simulators across 60 countries. Most recent development involved Oil India, the second largest national oil and gas company in the country, who selected 3t to provide advanced simulator solutions, further cementing 3t's growing presence across South Asia.

By replicating the complexity of real-world scenarios in a risk-free environment, 3t empowers trainees to respond to highstakes situations with confidence and clarity. Whether managing well control events, procedural deviations, or system failures, personnel are given the space to make critical decisions, learn from their actions, and repeat high-pressure scenarios until mastery is achieved. This kind of immersive learning helps eliminate trial-and-error while dramatically improving both individual performance and team coordination.

This immersive realism isn’t achieved through just standard 3D rendering, as it's the result of deep-coded algorithms that model mechanical systems, hydraulic circuits, geophysical responses, and control feedback loops, delivering a simulation that behaves like a real rig floor. This dynamic environment encourages trainees to think and respond as they would in live operations. For example, if an incorrect kill procedure is initiated during a simulated kick, the well doesn’t merely “fail” with a warning, it simulates the blowout path, kick velocity, pressure fluctuation, and containment window, all in sync with live rig instrumentation and control systems, enabling the team to think and respond in a dynamic environment

A standout example of this approach in action is 3t’s partnership with SADA, Saudi Arabia’s leading energy training provider. Tasked with creating a fully immersive learning environment at SADA’s state-ofthe-art training centre, 3t deployed a suite

of advanced simulators designed to deliver real-time operational realism. Beyond the simulators, 3t also introduced Virtual Reality solutions for SADA, allowing trainees to immerse themselves in realistic drilling scenarios safely and effectively, maximising downtime with engaging learning experiences. Additionally, 3t implemented its flagship Training Management Solution, streamlining resource allocation and optimising training efficiency by tracking materials, equipment, and instructor use, ensuring a seamless and impactful learning process. Overall, the result was a transformative shift in how drilling and well control training was delivered, bridging the gap between theoretical knowledge and field-ready competency.

3t goes beyond building the world-class technology, it also delivers digital twins of live assets and operations, embedded with realtime physics and adaptive interactivity. By providing a risk-free environment, personnel can practice both standard procedures and emergency responses, dramatically reducing the likelihood of real-world errors. Simulation also enables companies to test and optimise operational workflows, helping increase productivity and production performance.

Yet even with all these global credentials, 3t’s most exciting chapter may be unfolding right now in the United States.

Expanding Horizons: 3t’s Growth in the US Market

Recognising the momentum and complexity of the US energy sector, 3t is in the process of executing a bold expansion strategy to become a dominant force in the regional training landscape. This ambition is now taking shape in Houston, Texas, one of the energy capitals of the world, where 3t recently acquired ALL STOP! training, a respected safety training provider with deep roots in emergency response instruction across the Gulf Coast.

The acquisition significantly expands 3t Training Services’ US footprint, with two training centres, experienced instructors, and regional industry ties to its already formidable training infrastructure - as well as bringing in over 50 years of combined training experience.

This acquisition and full rebrand to 3t is a major milestone in its American growth. The flagship training facility in Houston is equipped with cutting-edge immersive training facilities and is designed specifically to meet the training demands of all local energy professionals. From advanced survival simulations to high-risk safety programs, the centre is engineered to deliver hands-on, high-impact learning in an environment that mirrors the pressures and complexity of real-world energy operations. The offering is bolstered by a second training centre located in Houma, Louisiana, where digital learning will take centre stage.

One of the centre’s most high-profile accomplishments to date was its role in preparing Aisha Bowe, NASA space engineer, for her suborbital mission with Blue Origin. Drawing on its expertise in safety-critical training, 3t customised aspects of its Houstonbased programs to meet the stringent physical and psychological demands of spaceflight, an extraordinary demonstration of how its technology can adapt beyond traditional oil and gas contexts. For Bowe, who has made history as the first Bahamian woman to take to space, 3t’s training delivered not only technical readiness, but a deep foundation

of mission resilience, underscoring 3t’s capability to support training at the highest levels of performance.

Looking ahead, 3t’s US strategy is anything but incremental. The company is committed to developing customised training programs that directly address the operational challenges faced by American energy companies. 3t is actively looking to forge partnerships with key players across oil, gas, renewables, and heavy industry, co-creating learning pathways that are measurable, immersive, and aligned to emerging industry needs.

Technology investment remains central to this approach. 3t is continually enhancing its simulation platforms and digital learning tools, ensuring that each US-based training initiative, whether delivered on-site or remotely, remains globally competitive and fully accredited, underpinned by its ISO accredited status.

As the energy sector continues to diversify and digitalise, 3t is perfectly positioned to lead the next wave of workforce transformation globally. By blending cutting-edge simulation technology and scenario-based training, 3t isn’t just training the energy professionals of today, it’s preparing the leaders of tomorrow. 

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COMMUNITY news

AM Sci Tech seals further deal at Aberdeen Energy Park

Specialised Seals International launches with £250,000 Investment in new facility at the Energy Development Centre Facility

AM Sci Tech, a subsidiary of Hurstwood Holdings, the owner of Aberdeen Energy and Innovation Parks, has welcomed a further new occupier to the Energy Park in Bridge of Don.

Precision engineering company, Specialised Seals International has officially launched its brand new business from a 1,549 sq ft unit at the Energy Development Centre.

Founded in 2024 by respected father-and-son team, Bob and Liam Stephen, the company brings extensive experience in technical design, manufacturing and operations. 

UK’s Minister for Nature celebrates Viper Innovations’ CSR success story at Viper Woods Cabin opening ceremony

The UK’s Parliamentary Under-Secretary of State (Minister for Nature), Mary Creagh, attended Viper Woods cabin opening ceremony in Stogumber, Somerset, on Tuesday 8th April, hosted by Viper Innovations – a Daas-model business working in global critical industries including subsea technology, with offices in Aberdeen, Portishead, and Houston.

The Minister’s presence marked a show of support and recognition for what the company has achieved for the environment and for bringing local children closer to nature. She was also joined at the event by Tiverton and Minehead MP, Rachel Gilmour, and Somerset Council Chair of Authority, Mike Best. 

Denholm Energy Services acquires Glacier Welding Solutions

A world-class name in specialist energy services has expanded its engineering footprint in central Scotland.

Denholm Energy Services has acquired Glasgowbased weld clad overlay specialists, Glacier Welding Solutions, for an undisclosed sum from parent company Glacier Energy Holdings. The move is seen as key to further increasing the company’s foothold in traditional energy markets and growing its UK presence.

Glacier Welding Solutions has an enviable reputation for reliable, ethical and high-quality service provision. All management and staff will remain with the company, while continuing to be led by Robert Hutcheson as managing director.

The acquisition – the third this year in the engineering division – will enhance Denholm Energy’s specialist energy engineering portfolio. 

Vysus Group continues growth focus with £5 million in new contracts

Vysus Group continues growth focus with £5 million in new contracts

The raft of contract wins and extensions relate to Vysus Group’s Asset Management consulting services and have been awarded by major oil and gas companies, LNG operators, petrochemical firms, and fertiliser producers across Europe, North America, and Southeast Asia.

Vysus Group, which is headquartered in Aberdeen and has offices in more than 15 countries, provides technical and regulatory advice to the complete energy spectrum including renewables, hydrogen, nuclear, and oil and gas as well as adjacent industries such as power generation and chemical processing. Its expertise spans the full lifecycle from geoengineering and grid connectivity to asset and risk management. 

Grandholm acquires RSD Supplies & Services in sixfigure deal

In a strategic move to enhance global procurement solutions, Grandholm Production Services has acquired Aberdeen-based RSD Supplies & Services in a six-figure deal.

RSD was formed in 1999 as a one stop solution to source and supply a wide range of essential highvolume products, including general consumables, components, and equipment, to support on and offshore operations.

Based in Glasgow, Grandholm Production Services owns and operates an international business, manufacturing heat transfer cooling components for world-leading refrigeration brands. It also owns Vantage Tags, a specialist business supplying bespoke safety tags for safety critical sectors. 

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Balmoral Comtec backs renewables with millionpound wave and current simulation facility

Aberdeen, 02-04-2025: Balmoral Comtec, a Balmoral Group company and a leading provider of buoyancy, protection and insulation services to the global offshore energy market, has invested £1 million in the development of a state-of-the-art Wave and Current Simulation Facility at Balmoral Business Park in Aberdeen. The purpose-built facility simulates surface, subsea and seabed conditions, making it suitable for evaluating offshore wind, solar and other subsea systems under dynamic water conditions.

Supported by partial funding from the Energy Transition Zone (ETZ) Ltd of £74,000, this innovative facility underscores Balmoral Comtec’s ongoing commitment to advancing renewable energy solutions and supporting the energy transition. 

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UK North Sea Energy Review

By Tsvetana Paraskova

The implications of the Chancellor’s Spring Statement on the energy industry, the sentiment in the supply chain industry, and mergers and acquisitions were the highlights in the UK North Sea oil and gas industry in the past few weeks.

Offshore Energies

UK, the leading trade body representing more than 400 firms across the UK’s energy mix, responded to the Chancellor’s Spring Statement as it continues to campaign for a homegrown energy future that unlocks growth while safeguarding energy security, jobs, and communities.

“Energy security is national security and key to growth. In an increasingly volatile world, the widening gap between the energy we produce and what we import matters,” Whitehouse added.

“Producing our own domestic oil and gas alongside accelerating homegrown offshore wind, carbon capture and hydrogen pays UK taxes, supports jobs and retains the supply chains we need to build our energy future.”

The Spring Statement was published days after OEUK’s Business Outlook 2025 report, which showed that UK energy reserves could cut imports and boost growth.

Under the right business conditions half of the 13-15 billion barrels of oil and gas the UK is projected to need by 2050 could be produced at home, the report found. This would add up to £150 billion of gross value to the UK economy on top of the £200 billion from planned production, safeguarding energy security, jobs, and lower carbon emissions alongside an acceleration of renewables.

“We heard the Chancellor underline the need for all parts of the economy to drive growth. With the right policies in place to attract investment, the UK offshore energies sector and its highly skilled people can help deliver this opportunity,” said OEUK Chief Executive David Whitehouse.

The independent Climate Change Committee has estimated that the UK requires 13-15 billion barrels of oil and gas by 2050, the target date for the economy to achieve net zero. The UK is on track to produce 4 billion of these barrels. But the report finds with the right policies to encourage firms to invest, another 3 billion barrels could be produced at home to meet half of the UK’s needs rather than increasing its reliance on imports.

By 2050, when UK electricity demand is expected to more than double, oil and gas will still form a fifth of UK energy needs, according to the report.

“The future of the North Sea is in our hands. Our report shows as we work together to accelerate renewables the UK must make the most of its own oil and gas – or choose to increase reliance on imports,” OEUK’s Whitehouse commented.

OEUK has also published its 2025 Supply Chain report, which found that without a pipeline of domestic UK projects enabled by pragmatic policy, a sentiment survey reveals nine companies out of every 10 see more attractive opportunities to grow their business overseas due to uncertainty and a less positive business environment at home. Low revenues from renewables and declining investor confidence are key barriers the supply chain industry faces in the UK right now, according to the report.

The government and industry could take several key steps to anchor world class offshore energy companies in the UK. These include industry initiatives aimed at fostering better collaboration across the supply chain, as well as moves to ensure that the government champions the UK energy supply chain capability in offshore wind, hydrogen, and carbon capture and storage (CCS).

“The UK is competing internationally for energy investment so it’s concerning that many offshore energy supply chain firms see more attractive opportunities to grow their business overseas,” Katy Heidenreich, OEUK’s supply chain and people director, said.

“To grow the whole UK’s economy, we need energy policy that supports continued investment in homegrown oil and gas alongside an acceleration of renewable energy.”

Around 60 percent of companies surveyed for the report are diversifying into offshore wind, hydrogen, and carbon capture and storage. However, business revenues from renewables and CCS still represent a relatively low proportion as they make up between zero and a fifth of their turnover, Heidenreich said.

“It’s good to export our expertise but that should never come at a cost to work we need to get done in the UK,” Heidenreich noted.

The North Sea Transition Taskforce, backed by the British Chambers of Commerce, said in a report that the UK government needs to replace the current Energy Profits Levy on North Sea oil and gas operations as soon as practically possible and not wait until the sunset clause of the tax regime expires in 2030.

“Central to this should be a replacement of the Energy Profits Levy as soon as is practicable by a new regime that is proportionate and adjustable in predictable ways in response to changes in the price of oil and gas,” the taskforce said in the report.

“Waiting until the sunset clause expires in 2030, as suggested by the HMT consultation, is to wait too long. Though the intent of the consultation appears to be positive, HMT should recognise that the current tax puts the industry in the UK at a competitive disadvantage and is throttling investment.”

In company news, NEO Energy has announced a strategic merger with Repsol Resources UK, creating a leading independent producer in the North Sea.

Under the terms of the deal, the combined business will be jointly owned by NEO (55 percent) and Repsol UK (45 percent) and have a large and diverse asset portfolio which is expected to generate material cash flows and provide a platform for organic and inorganic growth. Repsol will retain US$1.8 billion of the decommissioning liabilities related to its legacy assets, enhancing the cash flows of the combined business.

The combined group will be renamed NEO NEXT Energy Limited and is expected to become one of the largest producers in the region.

developed as a subsea tie back to the bp-operated central processing facility (CPF) of the Eastern Trough Area Project (ETAP).

The deal to buy JUK is in line with Ithaca Energy’s strategy to pursue value-accretive mergers and acquisitions (M&A), adding high-quality assets in its core UK Continental Shelf market.

THREE60 and COMS Energy have announced a strategic alliance aimed at delivering industryleading pre-commissioning, commissioning, and completions services. This initial three-year agreement will cover the oil and gas upstream, midstream, and downstream sectors, as well as energy transition industries.

The companies will partner to use the combined experience and capabilities. THREE60 have a successful track record in providing commissioning services to oil and gas customers in UK, Africa, and the Middle East, while COMS Energy, through its parent company, provides a strong track record of delivery and growth in the highly regulated nuclear industry.

Peterson Energy Logistics has secured a contract to provide a comprehensive suite of services to support Spirit Energy’s operations across the North Sea and East Irish Sea. Peterson will deliver a range of work including technology, cargo operations, warehousing, quayside services and road transport until end of field life.

Waiting until the sunset clause expires in 2030, as suggested by the HMT consultation, is to wait too long.

Completion of the transaction remains subject to approvals from the relevant authorities and regulatory consents and is expected during the third quarter of 2025.

In another M&A transaction, UK independent production and growth company, Ithaca Energy, has signed a sale and purchase agreement to acquire the entire issued share capital of JAPEX UK E&P Limited (JUK) from Japan Petroleum Exploration Co. Ltd for an enterprise value of US$193 million based on an effective date of 1 January 2024.

JUK holds a 15-percent working interest in the Seagull oil field in the UK North Sea. The transaction, which is subject to the satisfaction of certain conditions including regulatory approval, will increase Ithaca Energy’s working interest in Seagull from 35 percent to 50 percent, equalling bp’s interest as the field operator. The Seagull oil field in the UK Central North Sea, with over 300 mmboe in place, is a high margin producing field,

Imrandd, a data specialist and engineering consultancy, has successfully renewed its contract with Apache North Sea. This renewal extends Imrandd’s ongoing provision of integrity data analytics and onshore integrity engineering support across all seven of Apache’s North Sea assets.

In addition to maintaining the integrity of the topsides pressure systems equipment for Apache’s offshore assets, the contract has also expanded to pipeline capability including the provision of a senior pipelines engineer. This enhances Imrandd’s scope of work to deliver its advanced data-driven integrity management solutions across both topsides and subsea infrastructure.

Petrofac’s Asset Solutions division has been awarded a collection of scope expansions and new contracts in the first quarter of 2025, totalling US$500 million.

The awards – which realise growth in Asset Solutions’ core markets and target growth geographies, including the UK, Europe, Middle East, Africa, Asia Pacific, and US – span late-life asset management, decommissioning, and integrated services. 

A life cycle solutions company enabling a sustainable future.

Europe Energy Review

By Tsvetana Paraskova

Norwegian Sea. The field came on stream two years after the Norwegian authorities approved the field development plan.

increased to new record highs. With nuclear output stable, low carbon generation was a record 65.0 percent for the year.

Project start-ups in Norway, the UK’s renewable energy records and policies, and a number of wind, solar, and battery deals and milestones marked the past month in Europe’s energy industry.

Oil & Gas

In Norway’s Arctic waters, Equinor started up on 31 March the Johan Castberg oil field in the Barents Sea, which will produce oil for 30 years.

At its peak, Johan Castberg can produce 220,000 barrels of oil per day, while total recoverable volumes are estimated at between 450 and 650 million barrels.

“The Johan Castberg field will contribute crucial energy, value creation, ripple effects and jobs for at least 30 years to come,” said Geir Tungesvik, Equinor's executive vice president for Projects, Drilling and Procurement, adding that the company expects this major field development to repay its $8 billion investment within two years.

Equinor also launched the Halten East natural gas field in the Kristin-Åsgard area in the

The recoverable reserves of gas and condensate at Halten East are estimated to be around 100 million barrels of oil equivalent. The gas will be sent to Kårstø from Åsgard B, from where it will be exported to Europe via pipeline.

Low-Carbon Energy

The UK government has started seeking views on its vision for the North Sea’s clean energy future, which aims to seize tremendous opportunities created by wind, carbon capture, and hydrogen. The government looks to deliver a managed and sustainable transition for the oil and gas sector and its workforce. The North Sea Transition Authority (NSTA) plays a crucial role in helping the government implement its plans and also forms part of a consultation on ways of fostering a worldleading offshore clean energy industry.

“The North Sea’s immense energy and decarbonisation resources give the UK an opportunity to chart its own course through the transition, driving investment and job creation along the way,” said Stuart Payne, NSTA Chief Executive.

“Transformation on this scale is never straightforward, but through dialogue, collaboration and effective planning, we can arrive at the future we want and even accelerate the process.”

New statistics released by the Government at the end of March showed that renewables generated a record 50.8 percent of the UK’s electricity in 2024 – the first year in which renewables have exceeded 50 percent, and a substantial increase on the previous high of 46.4 percent in 2023.

Production from renewable technologies in 2024 increased 7 percent to a record 144.7 TWh last year, and a record share of 50.8 percent of electricity generation, passing half of generation for the first time ever in the annual data, the government’s Energy Trends report said. Wind generation increased by 2 percent to a new record high. Bioenergy and solar output also

At the same time, power generation from fossil fuels dropped to levels last seen in the 1950s, the data showed.

“The UK is moving away rapidly from fossil fuels to low-cost renewables which bring down consumer bills, with wind providing the bulk of our clean power,” RenewableUK’s Deputy Chief Executive Jane Cooper said, commenting on the figures.

“The Government has a golden opportunity to secure a record amount of new wind and solar farms in this year’s auction for new projects, but we can only achieve this if we get the right framework in place to attract billions in private investment.”

UK Chancellor Rachel Reeves said in her Spring Statement that the Government would remove Climate Change Levy costs from electricity used to produce green hydrogen.

This move would reduce electricity costs for billpayers and boost energy security, RenewableUK’s Director of Future Electricity Systems, Barnaby Wharton, said.

“Green hydrogen generated in high-tech electrolysers using renewable electricity has an important role to play in decarbonising sectors like steel, chemicals and shipping, which are hard to electrify,” Wharton added.

The introduction of a ‘cap and floor’ mechanism for Long Duration Electricity Storage (LDES) is set to incentivise investments in such projects, RenewableUK’s Senior Policy Analyst Yonna Vitanova said, commenting on the move by energy regulator Ofgem.

The cap and floor scheme ensures investors receive a minimum amount of revenue to enable investment in LDES assets. The cap on revenue provides returns to consumers for their support, where LDES assets operate above the cap.

On 1 April, Great Britain achieved a new maximum solar generation record, the

National Energy System Operator (NESO) said. On 1 April between 12:30 and 1 pm, solar generated 12.2 GW of Britain’s electricity.

“This is a major milestone on our journey to operating zero-carbon electricity system for a period of time this year,” NESO said.

The Crown Estate has allocated £15 million for the next round of the Supply Chain Accelerator programme which seeks to kickstart investments in UK offshore wind-related port infrastructure and supply chain facilities.

The Crown Estate established the £50 million Supply Chain Accelerator last year to accelerate and derisk the early-stage development of UK supply chain projects servicing the offshore wind sector.

progress to the next stage of the allocation process. The decisions on which projects will be successful will be based on value for money and affordability.

The European Commission has launched a new call for proposals for key cross-border EU energy infrastructure projects worth up to 600 million euros from the EU budget. The call, linked to the EU’s Connecting Europe Facility for Energy (CEF Energy), addresses funding proposals for studies and construction works and will be open until 16 September 2025.

This is a major milestone on our journey to operating zero-carbon electricity system for a period of time this year

The Crown Estate’s leasing round for three sites for floating wind farms in the Celtic Sea has entered its final stages. The process will lease sites off the coasts of Wales and South West England. Companies bidding to build the new wind farms have also shortlisted a range of potential locations in Wales and South West England for the assembly and deployment of the new turbines.

The UK government has shortlisted 27 electrolytic projects across England, Scotland, and Wales as part of the Hydrogen Allocation Round 2 (HAR2). The government said it looks forward to working with industry to deliver its vision for a thriving low carbon hydrogen economy in the UK.

The 27 shortlisted projects will need to pass a rigorous due diligence stage in order to

“Constructing the crucial missing links for seamless crossborder energy flows is essential – and the Connecting Europe Facility’s contribution is instrumental in this respect,” European Commissioner for Energy and Housing, Dan Jørgensen, said.

OEG, a provider of critical technical solutions and services to the global offshore energy sector, has invested in a new office in Edinburgh, as part of its long-term commitment to the UK offshore wind industry and goal to support the rapid expansion of offshore wind projects across Scotland and beyond.

“Edinburgh’s strategic location, close to key North Sea developments, major port infrastructure and the supply chain, makes it an ideal location to drive the next phase of offshore wind deployment and support the delivery of new projects,” OEG said.

TotalEnergies has announced investment decisions for six battery storage projects in Germany. In total, these projects amount

to 221 MW of new storage capacity and an investment outlay of 160 million euros.

These projects were developed by Kyon Energy, a TotalEnergies affiliate acquired in 2024, and most will use next-generation batteries supplied by Saft, a TotalEnergies affiliate and leader in advanced battery technology. Construction began at the end of 2024, and commissioning is planned for early 2026. TotalEnergies’ German project pipeline amounts to 13 GW of renewables and 2 GW of battery capacity.

RWE has signed a 10-year corporate power purchase agreement (CPPA) with five independent retail co-operatives –Lincolnshire Co-op, Scotmid Co-op, East of England Co-op, Southern Co-op and Central Co-op – to supply electricity from renewable energy sources to over 400 locations across the UK. Starting 1 April 2025, the long-term contract provides up to 53 gigawatt hours (GWh) of green electricity per year, enough to power over 400 retail stores, funeral homes, travel agents, and more. Sourced from the London Array offshore wind farm in the outer Thames Estuary, this agreement will see significant savings for the five co-operatives throughout the lifetime of the CPPA.

RWE has announced that the first turbine has been successfully installed at its Sofia Offshore Wind Farm, the 1.4 gigawatt (GW) farm in the shallow central area of the North Sea known as Dogger Bank.

The Sofia Offshore Wind Farm will comprise 100 Siemens Gamesa 14-MW turbines, making it one of the largest single offshore wind farms in the world. Sofia will generate enough renewable energy to power the equivalent of up to 1.2 million typical UK homes. The project is on track to be fully operational in the second half of 2026, RWE says. 

USA Energy Review

By Tsvetana Paraskova

The US oil and gas industry welcomed many of the Trump Administration’s energy policies such as unlocking Alaska’s resources and new Gulf of America lease sales. However, executives in the anonymous Dallas Fed Energy Survey did not spare criticism of the uncertainty the new administration brings to the industry with its trade policies and desire to have oil prices around $50 per barrel.

Dallas Fed Energy Survey Shows Uncertainty Rises

Oil and gas activity in the Eleventh District— Texas, southern New Mexico, and northern Louisiana—rose slightly in the first quarter of 2025, according to oil and gas executives responding to the quarterly Dallas Fed Energy Survey.

The business activity index, the survey’s broadest measure of the conditions energy firms face in the Eleventh District, remained in positive territory but declined slightly from 6.0 in the fourth quarter 2024 to 3.8 in the first quarter.

The company outlook declined by 12 points to -4.9, suggesting slight pessimism among firms. At the same time, the outlook uncertainty index jumped by 21 points to 43.1.

For the entire sample of companies surveyed, firms need $65 per barrel WTI oil price on average to profitably drill a new well, higher than the $64-perbarrel price when this question was asked in last year’s first-quarter survey.

capital of our business, with public energy stocks down significantly more than oil prices over the last two months,” an executive at an exploration and production firm said in comments to the survey.

“This uncertainty is being caused by the conflicting messages coming from the new administration. There cannot be "U.S. energy dominance" and $50 per barrel oil; those two statements are contradictory,” the executive noted.

At $50-per-barrel oil, we will see U.S. oil production start to decline immediately and likely significantly (1 million barrels per day plus within a couple quarters).

“At $50-per-barrel oil, we will see U.S. oil production start to decline immediately and likely significantly (1 million barrels per day plus within a couple quarters). This is not “energy dominance.” The U.S. oil cost curve is in a different place than it was five years ago; $70 per barrel is the new $50 per barrel.”

Across regions, average breakeven prices to profitably drill range from $61 to $70 per barrel. Breakeven prices in the Permian Basin average $65 per barrel, unchanged from last year.

However, in early April, the WTI oil prices crashed to $60 per barrel in a market selloff triggered by the Trump Administration’s tariffs and the OPEC+ group’s plans to increase supply from May by more than expected. Executives in the survey had already expressed in March concerns about how low oil prices would affect US drilling activity and production levels.

“The key word to describe 2025 so far is “uncertainty” and as a public company, our investors hate uncertainty. This has led to a marked increase in the implied cost of

Another executive was even more critical, saying that “The administration's chaos is a disaster for the commodity markets. "Drill, baby, drill" is nothing short of a myth and populist rallying cry. Tariff policy is impossible for us to predict and doesn't have a clear goal. We want more stability.”

A third E&P executive chimed in with “The threat of $50 oil prices by the administration has caused our firm to reduce its 2025 and 2026 capital expenditures.”

Added the executive, “Drill, baby, drill" does not work with $50 per barrel oil. Rigs will get dropped, employment in the oil industry will decrease, and U.S. oil production will decline as it did during COVID-19.”

Executives also pointed to the increased uncertainty around tariffs and steel product prices, which severely restricts producers’ ability to plan operations for any meaningful amount of time in the future.

Among oil and gas support services firms, executives say that the Administration’s tariff policy is injecting uncertainty into the supply chain.

One executive noted that “The increased drilling efficiency and capital discipline by the operator community is undermining the "drill, baby, drill."

Oil and Gas Industry Supports Regulatory Agenda

The industry is anonymously criticizing the Administration’s trade policies creating uncertainties, but publicly the oil lobby welcomes the efforts to roll back some regulations and open more federal land and waters to drilling.

The US Environmental Protection Agency has announced plans to reconsider several major rulemakings as part of a broader agenda to support American energy dominance.

In response, American Petroleum Institute President and CEO Mike Sommers said that “Voters sent a clear message in support of affordable, reliable and secure American energy, and the Trump administration is answering the call by moving forward on many of the priorities in API's five-point policy roadmap.”

Voters sent a clear message in support of affordable, reliable and secure American energy, and the Trump administration is answering the call by moving forward on many of the priorities in API's fivepoint policy roadmap.

“For far too long, the federal government has created too many barriers to capitalizing on the state’s energy potential,” Secretary Burgum said.

API also welcomed Interior Secretary Doug Burgum’s steps to unleash Alaska’s untapped natural resource potential and support President Trump’s vision of American Energy Dominance.

The Department of the Interior said that the Bureau of Land Management would pursue steps to expand opportunities for exploration and development in the National Petroleum Reserve in Alaska and the Coastal Plain of the Arctic National Wildlife Refuge.

“Interior is committed to recognizing the central role the State of Alaska plays in meeting our nation’s energy needs, while providing tremendous economic opportunity for Alaskans.”

API Vice President of Upstream Policy Holly Hopkins said that the institute “welcomes the administration’s efforts to fully leverage Alaska’s enormous resource base as a driver of revenue, economic growth and energy security.”

Hopkins also praised the Administration’s plans to hold a new lease sale in the Gulf of America later this year.

“This is an important step to restore a proAmerican energy approach to federal offshore leasing,” Hopkins said, after Interior Secretary Burgum directed the Bureau of Ocean Energy Management to hold the next scheduled oil and gas lease sale in the Gulf of America. BOEM anticipates publishing a proposed notice of sale in June 2025.

In early April, API welcomed the fact that President Trump’s so-called reciprocal tariffs that roiled global markets, including the oil market, exclude oil and natural gas.

“We welcome President Trump's decision to exclude oil and natural gas from new tariffs, underscoring the complexity of integrated global energy markets and the importance of America's role as a net energy exporter,” API’s Sommers said. 

Middle East Energy Review

By Tsvetana Paraskova

So OPEC+ producers “reaffirm commitment to market stability on healthier oil market outlook and adjust production upward,” OPEC said.

Lower-than-expected production from the US could help the Middle Eastern oil producers regain some market share with the supply increase they plan for May, analysts say.

The surprise production increase from the OPEC+ group and the efforts by the biggest national oil companies to diversify featured in the Middle East’s energy industry in the past month.

“In view of the continuing healthy market fundamentals and the positive market outlook,” the countries will raise their total production by 411,000 bpd in May. The increase for the month of May is equivalent to three monthly increments—comprising the increase of 138,000 bpd originally planned for May in addition to two monthly increments.

“The gradual increases may be paused or reversed subject to evolving market conditions. This flexibility will allow the group to continue to support oil market stability. The eight OPEC+ countries also noted that this measure will provide an opportunity for the participating countries to accelerate their compensation,” OPEC said.

The eight OPEC+ countries will now hold monthly meetings to review market conditions, conformity, and compensation. The eight countries decided to meet again on 5 May to decide on June production levels.

The OPEC+ announcement came hours after US President Donald Trump announced tariffs on nearly every country on what he described as “liberation day” for America on April 2. Since then, the White House has announced a 90-day pause on most tariffs, with the exception of China, on which the tariffs were raised to more than 100 percent.

OPEC+ To Raise Oil Supply More than Expected

The countries of the OPEC+ alliance that have been cutting oil production by a total of 2.2 million barrels per day (bpd) announced in early April that they would continue to ease these cuts in May. Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman reviewed during an online meeting the global market conditions and outlook and concluded that the oil market outlook is healthier and warrants a production increase.

The double whammy of tariff-fuelled recession fears and concerns about oversupply from the OPEC+ production hike crushed oil prices in the first half of April. Brent oil prices crashed to the low $60s per barrel, losing about 15 percent in the first ten days of April.

The decline in oil prices could put US oil production gains in jeopardy as the price of the US benchmark WTI crude oil slumped to below the levels that producers believe are enough to profitably drill a new well. In the Dallas Fed Energy Survey for the first quarter, producers in Texas, Louisiana, and New Mexico indicated that they need an average $65 per barrel price to profitably drill a new well.

On the other hand, oil prices in the low $60s are not enough to plug the budget deficits the top Middle Eastern oil-producing countries are running this year. Saudi Arabia, for example, needs oil prices at about $90 a barrel to balance its budget.

“While OPEC+ said the supply increase is due to a more positive outlook, it seems there is more behind this move,” Warren Patterson, Head of Commodities Strategy at ING, wrote in an analysis in early April.

“US President Trump is taking a more hawkish view towards Iran and Venezuela with stricter sanctions. OPEC+ might feel that this provides it with the opportunity to increase supply. OPEC+ might see this as an opportunity to boost supply, especially after Trump announced secondary tariffs for buyers of Venezuelan oil and threatened similar measures for buyers of Iranian and, potentially, Russian oil,” Patterson added.

“Finally, there are also suggestions that the group decided to increase supply to punish members who have been consistently producing above their production targets,” according to the commodities strategist.

Saudi Arabia Cuts Oil Prices to Asia

Days after OPEC+ announced a production hike for May, the leader of the group and the world’s largest crude oil exporter, Saudi Arabia, slashed the price of its oil loading for Asia in May to the lowest premium over regional benchmarks in nearly four years. The Saudi cut of $2.30 per barrel for the Arab Light grade loading in May for Asia was the steepest drop in the premium over the Oman/ Dubai average in two years. Arab Light in Asia will now sell at a premium of $1.20 per barrel over the Dubai/Oman benchmark, off which Middle Eastern producers price their crude going to Asia.

The steep drop in Saudi pricing, which is typically closely followed by other Middle Eastern exporters, increased speculation among analysts that Saudi Arabia is intent on regaining market share amid low prices.

Middle East NOCs Announce Diversification Moves

While oil markets are in turmoil, the largest national oil companies (NOCs) of the top Middle Eastern producers announced several major deals and milestones in carbon capture, hydrogen, and petrochemicals.

Saudi Aramco has launched the Kingdom’s first CO2 Direct Air Capture (DAC) test unit, capable of removing 12 tonnes of carbon dioxide per year from the atmosphere. The pilot plant is developed in collaboration with Siemens Energy and represents a significant step in Aramco’s efforts to expand on its DAC capabilities.

through the capture and storage of carbon dioxide. BHIG is expected to commence commercial operations to produce blue hydrogen in coordination with Aramco’s carbon capture and storage (CCS) activities in Jubail.

Saudi Aramco and the biggest Chinese refiner Sinopec signed an agreement for a planned petrochemical expansion at the Yanbu Aramco Sinopec Refining Company (Yasref) refining complex in Yanbu, on the west coast of Saudi Arabia.

The planned Yasref expansion aligns with our downstream strategy to unlock the full potential of our resources, including converting up to four million barrels per day of crude oil into petrochemicals by 2030

Aramco will look to achieve cost reductions that could help accelerate the deployment of DAC technologies in the region. Aramco and Siemens Energy intend to continue working closely together with the aim of scaling up the technology, potentially laying the foundations for large-scale DAC facilities in the future, the Saudi oil giant said.

Aramco has also completed the acquisition of a 50-percent equity interest in the Jubailbased Blue Hydrogen Industrial Gases Company (BHIG). The agreement brings together experts in their respective fields with the aim of providing the Jubail Industrial City area with hydrogen, including lower-carbon hydrogen, at scale.

BHIG targets the production of hydrogen, including lower-carbon hydrogen from natural gas, also referred to as “blue hydrogen”,

The agreement for petrochemical expansion comes as both Aramco and Sinopec look to diversify the use of crude oil into the production of petrochemicals. Demand

for petrochemicals will continue to drive oil demand, while transportation fuel demand has started to level off in many major markets, including China.

“The planned Yasref expansion aligns with our downstream strategy to unlock the full potential of our resources, including converting up to four million barrels per day of crude oil into petrochemicals by 2030,” said Mohammed Y. Al Qahtani, Aramco Downstream President.

Sinopec President, Zhao Dong, commented,

“The Yasref expansion project represents a significant milestone in our bilateral partnership, ushering in a new phase of deeper and more far-reaching collaboration. We expect the Yasref expansion project to unlock new dimensions of collaborative potential as we navigate the energy transition.” 

WANG GUOZHANG/FOR CHINA DAILY

Norway Energy Review

By Tsvetana Paraskova

Operators offshore Norway made new oil and gas discoveries and started up oil and gas fields, while also investing in low-carbon energy projects.

“We are on a hot streak in Norway,” DNO executive chairman Bijan MossavarRahmani said.

“Our latest and most exciting discovery this year, Kjøttkake, is close to existing infrastructure in the Troll-Gjøa area, and we will be relentless in pursuing its commercialization.”

Following its exploration success, DNO has stepped up purchases of producing assets to balance its Norwegian portfolio and help fund coming developments. In early March, DNO announced the transformative acquisition of Sval Energi Group AS, which will increase North Sea 2P reserves from 48 million barrels of oil equivalent (boe) to 189 million boe post-closing and 2C resources from 144 million boe to 246 million boe (pro forma figures as of year-end 2024).

The Norwegian major expects that this major field development with a price tag of NOK 86 billion ($8 billion) will be repaid in less than two years.

At Johan Castberg, 12 of the 30 total wells are ready for production, and this is sufficient to bring the field up to expected plateau production in the second quarter of 2025.

“Johan Castberg opens a new region for oil recovery and will create more opportunities in the Barents Sea. We've already made new discoveries in the area and will keep exploring together with our partners,” commented Kjetil Hove, Equinor's executive vice president for Exploration & Production Norway.

“We've identified options to add 250550 million new recoverable barrels that can be developed and produced over Johan Castberg.”

Norwegian oil and gas operator DNO ASA has announced an oil and gas discovery in the Kjøttkake exploration well in Northern North Sea license PL1182 S in which the company holds a 40 percent operating interest. The discovery was made in Paleocene injectite sandstones of excellent reservoir quality with preliminary estimates of gross recoverable resources in the range of 39 to 75 million barrels of oil equivalent (MMboe), with a mean of 55 MMboe, DNO said.

Located just 27 kilometers northwest of the Troll C platform and 44 kilometers southwest of the Gjøa platform, Kjøttkake is DNO’s tenth discovery since 2021 in the TrollGjøa exploration and development hotspot, following Røver Nord, Kveikje, Ofelia, Røver Sør, Heisenberg, Carmen, Kyrre, Cuvette, and Ringand.

Equinor began production from its massive Johan Castberg oil field in the Barents Sea on 31 March, which will boost Norway’s oil production this year and sustain its output and exports into the next few years.

Johan Castberg will be producing for 30 years and is set to offset some of the natural decline at mature fields in the NCS. At peak production levels, Johan Castberg can produce 220,000 barrels of oil per day, and recoverable volumes are estimated at between 450 and 650 million barrels.

“The Johan Castberg field will contribute crucial energy, value creation, ripple effects and jobs for at least 30 years to come,” said Geir Tungesvik, Equinor’s executive vice president for Projects, Drilling and Procurement.

“We've identified options to add 250-550 million new recoverable barrels that can be developed and produced over Johan Castberg.”

The field’s development created a lot of work for the domestic supply chain, Equinor noted.

The Norwegian supplier industry accounted for more than 70 percent of deliveries to the project during the development phase. In operation, this share will increase to more than 95 percent, with a Northern Norwegian share of more than 40 percent.

In terms of revenues, 84 percent of the revenue from the field will be transferred to the Norwegian state through tax and the state’s direct participating interest.

Equinor has also started production at the Halten East development in the Norwegian Sea, two years following approval from Norway’s authorities. The new gas field will boost Norwegian supply to Europe at a time when the continent needs more non-Russian gas for its energy security.

Halten East, a tie-in development in the Kristin-Åsgard area in the Norwegian Sea, consists of six gas discoveries and flexibility for three prospects in addition, utilizing existing infrastructure and processing capacity at Åsgard B.

The reservoirs of Halten East contain gas and condensate, estimated to be around 100 million barrels of oil equivalent. The gas will be sent to Kårstø from Åsgard B, from where it will be exported to Europe via pipeline.

“Halten East demonstrates the importance of area solutions and cooperation between licence owners and authorities to realise the full resource potential on the Norwegian continental shelf,” said Kjetil Hove, executive vice president for development and production on the Norwegian continental shelf.

“We have a large portfolio of projects that will connect discoveries to our producing hubs. Equinor expects to put over 30 such projects on stream at the NCS within 2035.”

Equinor’s exploration, development projects, and operation of fields on the Norwegian shelf continue to generate value for the Norwegian economy with the ripple effects the activity creates.

A report from Kunnskapsparken Bodø (KPB) found that Equinor procured goods and services with a total value of NOK 142.6 billion ($13 billion), an increase from NOK 134 billion ($12.2 billion) in 2023. A total of 93 percent of the procurement value came from Norwegian suppliers located in 260 different municipalities. This resulted in an employment effect of more than 85,000 fulltime equivalents.

“Looking towards 2035, Equinor plans to continue to ramp up activity. On the NCS alone, we want to see 250 exploration wells, 600 more development wells, 75 subsea developments, 3000 interventions, 2500 modification projects and 50 low-pressure projects,” said Kjetil Hove, Equinor’s executive vice president for EPN.

Apart from oil and gas exploration and development, Equinor invests in lowcarbon solutions even if the Norwegian energy major has recently scaled back its renewables operations.

Equinor and its joint venture partners in the Northern Lights CCS project, Shell and TotalEnergies, have made a final investment decision (FID) to progress phase two of the Northern Lights development. Northern Lights is developing an infrastructure to transport CO2 from capture sites by ship to the onshore receiving terminal at Øygarden in western Norway for intermediate storage, before being transported by pipeline for safe and permanent storage in a reservoir 2,600 metres under the seabed.

The investment in the second development phase of Northern Lights will be 7.5 billion NOK, or $685 million. This includes the award of 131 million euros, (or 1.5 billion NOK) from the Connecting Europe Facility (CEF) funding scheme, approved by the European Commission last year.

Phase two of the development will increase the total injection capacity from 1.5 million tonnes of CO2 per year (Mtpa) to at least 5 Mtpa.

“As the recently published European Clean Industrial Deal makes clear, large-scale carbon capture, transport and storage will be crucial in the energy transition as it offers a solution for hard-to-abate industrial emitters to decarbonize their processes,” said Irene Rummelhoff, executive vice president for Marketing, Midstream and Processing in Equinor.

In offshore wind, the offshore wind organization in Norway has signed a memorandum of understanding (MoU) with the Galician Association of Metal Industries and Related Technologies (ASIME), to boost cooperation in steel procurement.

Under the collaboration agreement, Spain and Norway will help their respective supply chains to work together by combining Spain’s strong industrial manufacturing, steel production, turbine expertise, and logistics infrastructure with Norway’s expertise in offshore engineering, floating structures, marine operations experience, and harshenvironment operations.

“With this MOU, we aim to establish a framework for cooperation to advance the development of offshore wind in both Spain and Norway,” EU adviser in Norwegian Offshore Wind, Martine Farstad, said.

Norwegian suppliers to offshore wind saw export growth of nearly 70 percent in 2024 compared to 2023, the Norwegian Offshore Wind association said, citing the latest Export Report 2025 by Menon Economis.

“The competence Norwegian suppliers have built in the oil & gas and maritime industry is valuable to offshore wind projects all over the world. The global offshore wind market is expanding, and we know that Norwegian suppliers are well prepared,” commented Arvid Nesse, CEO of Norwegian Offshore Wind. 

Australia Energy Review

By Tsvetana Paraskova

The latest report is consistent with previous calls for new investment in gas as supply from the gas fields in Bass Strait deplete, AEMO chief executive Daniel Westerman said.

Australia Needs

More Investment in Gas Despite Renewables Boom

Australia needs more investment in natural gas supply to avert a supply crunch later this decade, the energy market operator said in its most recent assessment.

Production from the Longford Gas Plant, which has historically supplied two-thirds of the gas used in the East Coast Gas Market, will reduce before retiring at the end of 2033, according to AEMO.

Natural gas consumption is expected to decline with the switching from gas to electricity in the residential, commercial, and industrial sectors.

However, the risk of peak-day shortfalls and seasonal supply gaps in the southern states is expected to arise from 2028, with annual supply gaps emerging from 2029, AEMO said.

“New investment is needed to deal with structural supply risks from 2029 to maintain supply to homes and businesses including for gas-powered electricity generation,” the market operator noted.

In response to the report, the Australian Energy Producers association commented that GSOO “reaffirms the need for governments to fasttrack new gas supply, amid an improved supply-demand outlook that defers forecast seasonal and structural shortfalls by a year.”

The report showed that there was no room for complacency if the east coast is to avoid shortfalls, as AEMO found that ‘all scenarios identify the need for new supply investments to maintain supply adequacy’.

“The GSOO makes clear that governments and regulators must work with industry to remove regulatory barriers to new gas supply and investment to avoid shortfalls,” said Samantha McCulloch, chief executive of Australian Energy Producers.

“While 2028 may seem a long way away, the long lead time for major energy projects means governments need to act now to ensure Australian homes and businesses continue to have reliable and affordable energy,” McCulloch added.

Renewable energy installations are rebounding and reaching all-time highs, but natural gas supply, which will continue to play a major role in Australia’s energy system for decades, needs to rise, the market operator and oil and gas industry executives say.

More Investment Needed to Fill Expected Gas Supply Gaps

The annual Gas Statement of Opportunities (GSOO) report by the Australian Energy Market Operator (AEMO) showed the need for new investment in Australia’s central and east coast gas markets to address forecast supply shortfalls in the southern states.

Developed with updated inputs from industry, the GSOO is one of AEMO’s gas planning and forecasting reports that provide technical insights to support investors and governments in making informed decisions to benefit consumers.

From 2028, seasonal supply gaps may emerge in southern Australia if conditions lead to sustained high gas usage, while expanded production of uncertain supply will be needed to meet domestic and export positions in northern Australia.

Various options are being considered by the gas industry, including new supply, transportation and storage projects, and LNG regasification terminals. Australia will likely need a combination of solutions to supply and deliver enough gas to where it is needed in the longer term, AEMO said.

As Australia transitions to a net zero emissions future, gas will continue to be used by Australian households, businesses and industry, and support the reliability and security of the electricity sector.

“Flexible gas-powered generation will remain the ultimate backstop in a high-renewable power system,” Westerman said.

“Gas, alongside batteries and pumped hydro, will enable higher renewable penetration and support reliability as coal-fired power stations retire.”

Major industry players also noted the need for sufficient reliable gas supply to Australia’s domestic market.

ExxonMobil in 2024 completed the transformation of the Gippsland Basin Joint Venture from an oil and gas business to a gas business and will ensure the production system delivers the reliability the customers expect, David Berman, ExxonMobil Australia Commercial Director, said at the 2025 Australia Domestic Gas Outlook Conference in Sydney in early April.

At the gas development, fourth-quarter 2024 production was equal to the average of the previous 5 years and 6 percent higher than the fourth quarter of 2023, Berman said.

Majors Call for Policy Reforms

Despite a consensus on the problem with domestic gas supply and its causes, “there is less alignment on how to reclaim the investment certainty that is required to secure the capital to produce the energy Australia needs,” Exxon’s executive noted.

“This matters because investment is the key to ensuring reliable and affordable gas for Australian households and businesses.”

Exxon cannot control or influence many factors beyond Australia, but “by getting the policy settings at home right and putting our natural advantages to work, Australia puts itself in the best possible position to navigate global events,” Berman noted.

Policy stability will be vital for providing producers with the certainty they need to invest and the confidence buyers require to contract long term supply, Exxon’s executive added.

Shell Australia country chair Cecile Wake also noted the need for investments in her speech at the same event.

“Australia has an extraordinary opportunity to thrive and prosper through the energy transition, but to do so we need to: prioritise energy security for Australian consumers and for our regional trading and security partners; and attract significant and sustained private investment to our shores,” Wake said.

Shell called for reforms in regulations so that Australia could reduce complexity, drive increased productivity, increased investment and strong environmental outcomes.

Woodside Invests to Boost Gas Supply

The Gippsland Basin Joint Venture is investing in the development of new supply to deliver much-needed gas to south-eastern Australia ahead of winter 2027, Woodside Energy said in March.

The joint venture of Woodside and ExxonMobil’s subsidiary Esso Australia Resources Pty Ltd will invest AU$350 million (US$212 million) in the Turrum Phase 3 Project, which is expected to come online in 2027. Once operational, Turrum Phase 3 would supply four times more gas than Queensland supplied to the southern states in 2024, said Liz Westcott, Woodside executive vice president and chief operating officer Australia.

“Woodside is committed to supplying as much gas as we can to market through projects like this one,” Westcott said.

X

Woodside is committed to supplying as much gas as we can to market through projects like this one

“The regulatory and compliance hurdles we need to clear should be high by all means, but we shouldn’t have to clear hurdles which move, aren’t visible until you hit them and which once you’ve cleared them, spring up again and again,” Shell’s Wake said.

“In short, regulation that is both effective and efficiently administered is required to create an environment conducive to sustained investment over time.”

“The Turrum Phase 3 project, and the recently approved Kipper 1B project, will unlock additional gas that is needed to avoid future shortfalls. Every molecule of gas Woodside supplies from the Bass Strait fields is sold into the Australian domestic market for local manufacturers, power generators and homes.”

Renewables Could Lower Power Bills

Renewables could be the cheapest path to lower Australian energy bills, a new report by the Clean Energy Council showed.

If renewable energy rollout slows, Australian power bills could jump by 30 percent for households and 41 percent for small businesses by 2030, the council’s modelling revealed.

The modelling compares the Australian Government’s current ambition of 82 percent renewable energy by 2030 with the alternative, modelled by Frontier Economics for the Federal Coalition, which limits renewable energy at 54 percent and relies on coal and gas while waiting for nuclear power.

“Under this scenario Australia would have to increase its reliance on increasingly expensive and unreliable old coal generation, as well as significantly increase gas generation which is a much more expensive energy source. The net impact is higher power prices for all Australian homes and small businesses,” said Kane Thornton, Clean Energy Council Chief Executive.

“Our modelling confirms that continuing to deploy renewable energy will keep wholesale electricity prices as low as possible. Clean energy not only works for Australia but it’s the cheapest path forward for our electricity bills,” Thornton added.

The desire of Australian households to have some control over their power bills led to a boom in rooftop solar installations in 2024, the Clean Energy Council’s Rooftop Solar and Storage Report (Jul-Dec 2024) found.

For the fifth consecutive year, more than 300,000 Australian homes and businesses installed rooftop solar, the report showed.

Rooftop solar generated a total of 30,178 GWh of electricity in 2024 - 12.4 percent of Australia’s total power supply, which was up from 11.2 percent in 2023, and almost doubled from 6.5 percent in 2020.

However, only 4.5 percent of rooftop solar owners have an accompanying home battery attached—these findings have prompted the Clean Energy Council to reiterate its call for a national home battery rebate incentive of up to AU$6,500 (US$3,930) per household to help make home batteries more accessible.

The results reinforce the importance of establishing a national home battery rebate scheme, to ease the upfront costs associated with adopting home batteries, said Con Hristodoulidis, Clean Energy Council General Manager – Distributed Energy. 

RCP-EDR

ELECTRONIC DRILLING RECORDER

The RCP EDR is designed to give operators a clear, unambiguous overview of critical drilling and mud data processes The system has been developed by RCP to greatly improve how information is presented using the latest industrial technologies and user-friendly interfaces.

The RCP EDR offers a quick and cost-effective solution for clients considering a new installation or a partial upgrade to their existing drilling instrumentation systems Our highly experienced engineers and software developers allows us to tailor each new system to meet your exact needs meaning that you do not pay for functionality you will never use

The RCP EDR utilizes a variety of sensing technologies to monitor the drilling processes, (typically: Level, Pressure, Height, Temperature and Flow). Sensor output signals are received by the distributed I/O racks and are then processed by the EDR.

Processed information is then transmitted through network communication modules to each of the user interfaces including remotely networked PC’s and local HMI’s System and operator interface communications may utilize either: Fibre-Optic, Profinet, Profibus or Industrial Ethernet connection

BRENT OIL PRICES OVER

THE YEARS

1 YEAR AGO

1 Year Ago - $83.89

The structure of the Brent crude oil futures market fell to its weakest in 3 months, another indication that concern about tight supply for prompt delivery was easing. Global physical crude oil markets were weakening, reflecting soft consumer and industrial demand and rising supply from non-OPEC producers.

5 YEARS AGO

5 Years Ago - $33.06

Oil prices surged as the easing of lockdown measures, caused by the outbreak of Coronavirus, in some countries fuelled hopes for a return of demand. The price rose by 14% as some countries such as Italy, Spain and Nigeria became the first to begin easing measures, with details of UK firms returning to work also being released.

10 YEARS AGO

10 years ago - $65.15

Shell planned to decommission the massive Brent Delta oil platform in the North Sea by lifting its 24,000-tonne topside in one piece using the mega-ship Pioneering Spirit. This innovative method aimed to cut time, cost, and environmental risks. If successful, the ship planned to remove other platforms in the field, marking a major shift in offshore infrastructure dismantling.

At the heart of OGV Media Group is the OGV Community, a corporate membership service that connects energy sector organisations with our growing network of professionals, leveraging member engagement and platform traffic to maximize brand exposure.

Subscription to the OGV Community offers its members the following growing list of benefits:

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GINGER OFFSHORE GAS FIELD

BP has taken a final investment on the gas development. The project will include four subsea wells and subsea trees tied back to the Mahagony B platform. First gas from the project is expected in 2027.

TURRUM GAS FIELD –PHASE 3

ExxonMobil and Woodside have taken FID on the Turrum Phase 3 Gas Project committing an investment of A$350 million ($221 million). This phase will involve drilling five new wells in the Turrum and North Turrum gas fields to access undeveloped gas resources in the Gippsland Basin.

SEME OIL FIELD REDEVELOPMENT –PHASE 2

A new redevelopment phase has been announced at the field. The plan will potentially see the drilling of three oil wells in the H7 reservoir and two gas wells in the H8 reservoir, which have shown flow to the surface in past tests but were not yet brought into production. The project's start-up is expected by 2H 2028.

IRONG TIMUR FIELD AND BERANTAI EAST FIELD –WELLHEAD PLATFORM PROJECT

Vestigo has awarded MMHE an EPCIC contract for the fabrication of two wellhead platforms for the Irong Timur and Berantai East fields. Each wellhead platform has an approximate weight of 1,500 MT. Upon completion, the wellhead platforms will be deployed to support Vestigo's field development plan.

COMMON SEAWATER SUPPLY PROJECT (CSSP) –WATER INJECTION PROJECT

Iraq's Council of Ministers has approved the award of a seawater pipeline contract under the Common Seawater Supply Project (CSSP) to China Petroleum Pipeline Engineering Co., Ltd. (CPPE). The project, issued by Basra Oil Company (BOC), will be completed in 54 months, with 42 months dedicated to engineering, procurement, and construction (EPC) and 12 months for operation, maintenance, and training.

KUDA-TASI & JAHAL OIL FIELDS

Finder Energy has confirmed that the field will be developed via subsea wells tied to a central FPSO, which which will be located in water depths of 400m. Finder Energy has identified several FPSOs to be redeployed due to their expedited development.

BAOBAB FIELD PHASE V

Drydocks World has been awarded a contract to refurbish and extend the life of the Baobab Ivorien FPSO. Work will commence in May 2025. Under the agreement, the company will be responsible for structural enhancements and integration of technologies to boost the FPSO's efficiency and reliability.

DUYUNG PSC

Conrad has reported that the refinement of the project timeline and cost is progressing. The procurement process for major tenders is ongoing with some tender deadlines extended upon request from potential bidders. The estimated project cost will be updated after the tendering activities conclude.

HAMMERHEAD OIL FIELD

Saipem has signed a Limited Notice to Proceed (LNTP) contract with ExxonMobil Guyana involving the EPCI of subsea structures, umbilicals, risers, and flowlines (SURF) for the production facility and gas export system of the Hammerhead oil field. The LNTP allows Saipem to start early work activities, such as detailed engineering and procurement.

NORTE DE BRAVA BLOCK OIL DISCOVERY

Petrobras has identified hydrocarbons in an exploratory well in the Norte de Brava block, while drilling the 1-BRSA-1394RJS well, located in a water depth of 575 metres in the Campos basin. The operator will complete the well and assess the conditions of the reservoirs and fluids encountered. This data will help evaluate the potential of the area and guide the next exploratory activities. The well is currently undergoing final logging.

HUIZHOU 19-6 OIL FIELD

CNOOC has announced the discovery of with in place reserves of more than 730 MMbbls of oil. The field is located in water depths of approximately 100 metres. The recently completed HZ 19-6-3 well, drilled to a TD of 5,415m, flowed at rates of 413 b/d of oil and 2.41 MMcf/d of gas.

GATO DO MATO OIL FIELD

A final investment decision has been reached on the development of the field. Modec has signed a Purchase and Sale Agreement and a 20-year O&M contract with Shell to provide the FPSO for the project. TechnipFMC has won an integrated SURF and SPS contract for the project.

By Tsvetana Paraskova

Welcome To the Age of Innovation and Technology in Energy

Until a few years ago, the energy industry was slower than other sectors in adopting technologies and digitalisation to facilitate operations and reduce downtime and costs.

Now the rapid advancements in artificial intelligence and other innovative technologies to raise production and monitor assets are being embraced by energy firms, which are increasingly using various AI technologies and applications to remain competitive in a world of geopolitical upheaval and a push to drive down emissions.

AI Market in Oil & Gas Booming

The value of the AI in the oil and gas market is expected to increase by a compound annual growth rate (CAGR) of 23.12% by 2029, according to a report by ResearchAndMarkets.com.

The AI market in oil and gas is projected to be worth US$15.010 billion by 2029, triple compared to US$5.305 billion in 2024, per the report from November 2024.

Energy companies are expected to increasingly use advanced AI solutions to analyse the huge volumes of disparate data, and implement AI tech in resource analytics, drilling, extraction, and decision-making, with a focus on automation, safety, and predictive analytics, ResearchAndMarkets.com noted.

GE Vernova, the U.S. energy equipment manufacturing and services giant, sees AI helping in several major directions the operations and the future of the energy sector. According to John Karigiannis, Artificial Intelligence & Robotics Technology Manager Advanced Research Center, GE Vernova, these include predictive maintenance, fleet management, extension of the lifetime of components, accelerating the development of new materials, and enhanced and enriched decision making, as generative AI can offer assistance to engineers by helping to examine and analyse multi-modal data sources and factors.

Oil and gas executives in a recent EY survey said that the two highest opportunities for creating value from AI and emerging technology are predictive maintenance for heavy equipment and assets, and intelligent optimisation of operations performance.

“The new reality of the oil and gas industry requires building resilience through digital. Accelerating technology in subsurface and operations domains has the potential to unlock tremendous value,” Swapnil Bhadauria, EY Americas Oil & Gas Digital Operations Leader, says.

But the successful adoption of AI in oil and gas would require three key steps: leadership buy-in, culture change, and constant feedback, Bhadauria notes.

“The challenge is to clearly analyze the risk of various AI initiatives and weigh them against measurable benefits,” said Abhilash Krishna, Manager, Technology Consulting, Ernst & Young LLP.

“While reservoir simulations and drilling functions may face higher risks to using AI, they also have the opportunity for more significant rewards. Leaders who embrace that risk — and give their people permission to fail — will solve the AI puzzle sooner and gain an advantage.”

However, scaling AI is not the same as scaling cloud computing—the issues and tasks cannot be solved by only adding more power, says Matt Russell, Manager, Technology Consulting, Ernst & Young LLP.

“Everything must scale exponentially — people, processes and technology. Scaling your AI tools — and keeping them on track as your data inputs grow — requires a real organizational commitment,” Russell adds.

AI Already Benefiting Energy Producers

Executives attending the CERAWeek conference in Houston in early March said that AI is already leading to faster and cheaper oil production.

bp, for example, uses AI to steer drill bits and predict potential issues in wells before they could emerge, bp’s senior vice president of wells, Ann Davies, said.

“We are able to drill more wells per year and have a better capital allocation,” Davies added, just as bp announced a reset in its strategy to focus on oil and gas again, after years of attempts to boost presence in renewables and other low-carbon energy solutions.

In Texas, Percepto and Chevron have reached a six-month milestone to evaluate use of the drone company’s AIpowered remote inspection capabilities. The project has demonstrated promising improvements in operational efficiency and advancing workforce safety.

“With advanced technology, we can take a more proactive approach to managing our operations,” said Kerri Harvey, Chevron’s Midland Basin Operations Superintendent.

“This enables us to make smarter decisions and remain aligned with our focus on producing energy responsibly.”

The AI-powered drone monitoring enables Chevron’s teams to spend less time on the road and more time focusing on high-priority tasks.

“This not only keeps our workforce safer but also allows us to direct resources where they can make the biggest impact,” Harvey added.

Chevron also uses AI to analyse data, remotely control equipment, or model hydrocarbon reservoirs.

While Chevron works to power AI, Chevron employees are also using artificial intelligence to enhance their ways of working. AI helps paint a more accurate picture of the subsurface than traditional methods, enabling companies to determine which areas are good for oil and gas recovery, or which areas might be good for CO2 storage. AI also helps with keeping assets up and running for the delivery of reliable energy. Real-time sensor data and anomaly-detection methods help reveal problem areas such as leaks, Chevron says.

SLB, the world’s top oilfield services provider, has reinforced its collaboration with NVIDIA to develop generative AI solutions for the energy sector. The collaboration accelerates the development and deployment of industryspecific generative AI foundation models across SLB’s global platforms.

“As we navigate the delicate balance between energy production and decarbonization, generative AI is emerging as a crucial catalyst for change,” said SLB chief executive officer Olivier Le Peuch.

“Our collaboration with NVIDIA will accelerate the creation of tailored generative AI solutions, enabling our customers to optimize operations, enhance efficiency and minimize their overall footprint.”

SLB has recently won a major drilling contract by Australia’s Woodside Energy for its ultra-deepwater Trion development project offshore Mexico. The drilling will be AI-enabled, as SLB will oversee the delivery of 18 ultradeepwater wells using an integrated services approach and AI-enabled drilling capabilities to improve operational efficiency and well quality.

“SLB has extensive expertise in ultradeepwater drilling projects globally and advanced technologies, including AI and digitally enabled hardware, to bring these wells online safely, efficiently and reliably,” said Wallace Pescarini, president, Offshore Atlantic, SLB.

France’s TotalEnergies is using the AUSEA technology – developed in cooperation with the French National Centre for Scientific Research (CNRS) and the University of Reims ChampagneArdenne – in detecting and quantifying emissions in real-life conditions.

“The future of energy and AI cannot be shaped in isolation,” Ibrahim Al-Zu'bi, Senior Vice President of Sustainability & Climate at ADNOC Group, wrote in an article earlier this year.

“It requires a concerted global effort that brings together industry leaders, policy-makers and innovators to develop solutions that ensure both energy security and sustainability. Global partnerships are essential for addressing the challenges posed by AI’s energy needs and ensuring that AI fulfils its potential to drive a more sustainable future.” 

Unlocking the power of subsurface data: Optimising workflows in Petrel.

| by Julie Vonnet Product Marketing Lead, Cegal

Energy companies today thrive on their ability to integrate new research, machine learning (ML) models, and external data quickly into their subsurface workflows. But let’s be honest, this is not always a smooth process. For geoscientists working in Petrel*, bringing in cutting-edge tools often means diving into Python code, which can be daunting.

So how can we bridge this gap? How can geoscientists take advantage of ML and automation without having to become programmers? That’s where smarter integration tools like Cegal Prizm come in, making it easier to connect data, deploy ML models, and optimize workflows, all without the need for deep coding expertise.

| The challenge: Getting tech to work together

Subsurface experts, like geophysicists, geologists, and reservoir engineers, deal with a plethora of data from various sources, but the industry’s go-to platforms are not always built for seamless data integration. Converting files, transferring data, and aligning formats can be tedious and lead to errors.

Even when ML models exist to automate tasks like, for instance, fault detection or seismic analysis, integrating them into Petrel workflows can be a hassle. Many workflows slow down because they

depend on coding expertise to set up automation, connect external tools, or even just move data between applications.

| Smarter tools, not more code

Imagine being able to integrate ML models and external data directly into Petrel with just a few clicks, with very limited, or even no Python skills required. That’s exactly what tools like Cegal Prizm make possible.

By using this Python API designed for Petrel, geoscientists can:

• Deploy ML models or proprietary algorithms without writing code

• Seamlessly pull data from external sources into Petrel

• Automate repetitive tasks

• Share workflows easily across teams

For example, an ML model for fault detection, trained on 200 synthetic 3D seismic images, can easily be used inside Petrel without complex setup. Instead of exporting seismic data, running it through a separate Python process, and reimporting the results, geoscientists can apply the model directly within Petrel. The result? Faster interpretations with minimal manual effort.

| Say goodbye to the hassles of data transfer

One of the biggest headaches for geoscientists is moving data between Petrel and Python environments. cegal.com

by Julie Vonnet | Product Marketing Lead, Cegal

Typically, this involves exporting data, converting it into a usable format, running analyses, and then reformatting everything to bring it back into Petrel. Each step takes time and introduces room for error.

Cegal Prizm can change the game by automating these steps. Instead of manually exporting seismic volumes or well logs, users can retrieve data directly from Petrel into a Python-friendly format (like NumPy arrays or Pandas DataFrames), process it, and push the results back, all in a streamlined workflow.

This eliminates the need for back-and-forth file conversions and ensures data remains consistent and accessible.

| Collaboration without the complexity

In instances where geoscientists do manage to set up new and innovative workflows, sharing them across teams can be challenging. Python environments often differ from one machine to another, and minor version mismatches can break scripts. This makes it difficult for teams to adopt and scale new technologies efficiently.

A better approach is to centralize not just the workflows, but also the Python environment they rely on. Instead of requiring every geoscientist to install Python and manage dependencies locally, a cloud-based or on-premises system can host both the scripts and the environment in one place. This also simplifies version control, ensuring that all users are working with the same Python versions and dependencies, without the need to troubleshoot compatibility issues caused by differing environments.

Cegal Prizm allows Petrel users to run Python workflows seamlessly within Petrel through a user-friendly, Petrellike interface - eliminating the need to interact with code.

This means geoscientists can take full advantage of Python scripts, from simple arithmetic operations to advanced machine learning algorithms, without needing any coding knowledge. By removing the barrier of Python expertise, Cegal Prizm makes powerful tools and automation accessible to all users, regardless of their technical background.

| The future: More focus on geoscience, less on code

By making it easier to integrate ML models, external data, and automation into Petrel, geoscientists can spend less time wrestling with technical barriers and more time interpreting data and making critical analyses.

With intuitive tools that remove coding barriers, the industry can accelerate innovation and make advanced geoscience workflows more accessible to everyone, not just those with programming skills. The goal here is to make Python’s power available to all geoscientists, no matter their coding background.

The future of subsurface workflows is about smarter, faster, and more efficient ways to work. That future is already here.

Contact us | sales@cegal.com

Cegal is a specialist provider of Geoscience and IT services to the Energy industry.

• Geoscience Software

• Subsurface Data Management

• Petrotechnical Consulting

• High-Performance Cloud Computing

• Data Rooms

• IT Consulting and Services

’Petrel is a mark of SLB

The AI-Powered App transforming the recruitment industry for the energy sector

“Moblyze” is a technology company based in Texas and Aberdeen, that has reinvented the way in which talent & opportunity are brought together across the global energy sector. They have developed an Al powered application that is specifically built to help candidates seeking employment opportunities across fuel types in the current energy expansion.

Led by a team of domain experts with over 60 years of recruitment experience behind them in the energy sector and technology markets, 'Moblyze' has already seen major success, having just this month received almost $2M of funding from public and private investment companies.

Dubbed the 'Skyscanner of energy recruitment', and built with today’s dynamic energy sector in mind, Moblyze streamlines and reimagines the hiring process by matching skilled workers with roles in seconds. It also identifies upskilling pathways to help workers hop between oil & gas, renewables, nuclear projects.

Designed to make job-matching seamless, Moblyze gives employers real time access to the “all energy” workforce they need, while candidates simply create a profile and are matched with roles - swiping right to accept, left to decline, or simply sharing the job with other people in their network who may be better suited.

The new venture was developed by a team of energy recruitment and energy service

company executives led by CEO Chris Black. The exec team are based in Aberdeen and Houston and after more than 20 years navigating "archaic" recruitment systems, they recognized a crucial opportunity to modernize the process during a pivotal time for the industry.

Key backers of the business include Shane Corstorphine, former Chief Financial Officer of Unicorn travel markeplace 'Skyscanner', and entrepreneur and philanthropist Garreth Wood, son of Sir Ian Wood who founded global EPC business Wood plc'.

The Goverments of Scotland and McKinney Texas have also invested around $200,000 to support the platform's role in advancing energy workforce accessibility.

Chris Black said: "For decades, the energy sector has relied on outdated recruitment systems - some quite literally conceived in the last century. While the industry works to solve today's complex challenges, the way we connect talent to opportunity has remained stuck in the past.

For further information, please visit www.moblyze.me or scan the QR code on this page.

"With our deep industry expertise and the backing of key investors, we've built a platform that reimagines recruitment for the energy workforce, both today and in the future.

The transition ahead can feel uncertain, but Moblyze is designed to offer stability - helping workers and employers navigate the shift from high-carbon industries to a more sustainable energy future."

Moblyze has already received significant acclaim from the energy supply chain in the UK and US markets and looks forward to rolling out their concept to the rest of the key energy hubs in the coming years including the Middle East, SE Asia and Australian market place. 

Tackling benzene risks in oil and gas decommissioning

By Mark Burrup, Product Manager, Dräger

Decommissioning the North Sea’s numerous oil and gas assets will take, at a minimum, decades. According to the latest numbers from OEUK, spend will exceed £24 billion by 2033, as operators forge ahead with well P&A and asset removal, disposal, recycling and re-use.

Such a monumental undertaking means the industry must operate as efficiently and cost-effectively as possible. But, as always, this cannot be at the expense of safety.

By its very nature, decommissioning is a high-risk process. On top of the economical and logistical challenges of dismantling and removing structures, many of which have been in situ for decades, there are numerous environmental hazards, like the release of pollutants and greenhouse gases.

Benzene – a hidden danger in oil and gas decommissioning

One of the most harmful of these is benzene, a known carcinogen found in crude oil and gas.

As refineries, chemical plants, and storage terminals undergo decommissioning, residual benzene in pipes, tanks, and soil poses serious health risks to workers. Meanwhile the removal of offshore oil and gas assets involves removing or isolating structures, pipelines and wells that can release the colourless gas.

As well as being highly flammable, prolonged exposure to the gas can cause blood cancers, anaemia and damage to the bone marrow, as well as respiratory and neurological issues.  In the UK, benzene levels are under stringent control and occupational exposure limits (OELs) are strictly regulated so that exposures are cut to the lowest practical level.

Failure to comply can lead to severe legal and financial consequences, meaning nothing but the best detection and monitoring equipment will do.

Methods for managing the risk

Various methods are used in the industry to detect and quantify benzene, each with distinct advantages and limitations. Photoionization detectors (PIDs) provide rapid, real-time detection, while being portable, user-friendly, and effective for field applications. However, standard PIDs are non-specific and may detect a broad range of gases, leading to potential inaccuracies.

Gas chromatography is known for its high accuracy, but the method for recording is timeconsuming, requires trained personnel, and is not suited for real-time field measurements.

Colorimetric tubes offer a cost-effective, user friendly solution for on-site benzene detection, delivering rapid results without the need for specialised training. However, results can be subjective compared to electronic detection methods.

Finally, electronic benzene-specific monitors are tailored to offer high specificity, with the ability to perform real-time monitoring and data logging for regulatory compliance. While more expensive than basic detection methods, they provide enhanced accuracy and reliability for long-term monitoring.

Dräger’s role in enhancing worker protection

The selection of a benzene measurement method for decommissioning operations depends on three key factors: quality, time, and cost. Quality determines the level of accuracy required; time is critical as faster

results improve efficiency; cost is tied to the number and frequency of measurements that need to be completed.

As a leader in gas detection technology, Dräger provides a range of industry-leading solutions for benzene monitoring, ensuring safety in high-risk environments, specifically decommissioning sites.

The Dräger X-act® 7000 analysis system consists of Dräger MicroTubes and an electronic analysis device that lets you precisely measure gases such as benzene in the low ppb range. While our colorimetric tube system, Dräger-Tubes®, provides a cost effective and simple way to assess benzene concentrations in various decommissioning scenarios.

The Dräger X-pid® 9500 is our flagship detection device for benzene, combining PID and gas chromatography in an ATEX approved device to allow real time, on site laboratory quality benzene detection. It is controlled via a dedicated ATEX approved mobile phone App, to ensure ease of use and minimal training requirements.

By integrating Dräger’s advanced detection equipment into decommissioning operations, companies can maintain regulatory compliance, reduce health risks, and ensure a safer working environment. These tools empower safety teams to detect and respond to benzene exposure proactively, ensuring decommissioning of North Sea oil and gas assets can be completed while upholding the highest safety standards. 

REGISTRABLE ITEMS: A CRITICAL FACTOR IN OFFSHORE ASSET INTEGRITY

Between 2016 and 2021, nearly 50% of all reportable hydrocarbon releases in the UK Continental Shelf (UKCS) were linked to failures in traditional registrable items, according to figures published by the Health and Safety Executive (HSE). This includes well-known components such as dead legs, trunnions, deck penetrations, insulation terminations, spring hangers, small bore tubing, and flexible hoses — items that are often undervalued in integrity planning.

These components play a fundamental role in ensuring safe and reliable operations. However, their distributed nature, the historic reliance on manual tracking and inconsistent documentation have created gaps in how they are registered, inspected, and maintained.

Defining Registrable Items and Their Risk Profile

Registrable items are features or components of offshore infrastructure that require individual consideration for inspection, maintenance, and integrity assurance.

Examples include:

• Dead legs, which are susceptible to corrosion due to stagnant flow;

• Deck penetrations, which can serve as unmonitored ingress points for moisture or contaminants;

• Trunnions, often overlooked despite being high-risk in pressure-containing systems;

• Spring hangers, whose performance can deteriorate over time;

• Insulation, which can hide underlying degradation;

• Small bore tubing and flexible hoses, which may experience fatigue, vibration, or mechanical damage that leads to failure.

Each contributes to topsides system integrity but is often missed in risk assessments due to incomplete or outdated registries.

The Management Challenge

Despite their criticality, one of the core failings in the management of these items lies in visibility. In many cases, integrity teams are reliant on operational knowledge or historic walkthroughs — a process that introduces human error and inconsistency. As a result, opportunities for early intervention are missed, and the industry continues to see preventable releases traced back to components that, with better management, could have been controlled.

Bridging the Gap: Industry Shortcomings and a Call to Action

One of the most significant gaps is the lack of a clear owner. These components often fall between the lines of piping, structural, and mechanical disciplines, with no single function accountable for their complete lifecycle oversight. This ambiguity leads to inconsistency in how items are tracked, inspected, and maintained.

Another shortfall lies in the quality of asset records. Many offshore facilities operate with drawings and databases that have not been updated in years and modifications are made in the field but not reflected in system records. As a result, registrable items are either missing from official registries or inaccurately represented.

Inspection itself, while often diligent, is reactive by nature. Resources are directed toward high-profile equipment, while registrable items are inspected inconsistently or only after issues arise. The assumption that “minor items pose minor risk” no longer holds water in light of recent HSE data.

Towards a More Effective Approach

Addressing these challenges requires a strategic, system-wide approach to managing registrable items across the asset lifecycle. At GDi, an Oceaneering Company, we’ve begun to approach this challenge through an internal framework that considers four intersecting drivers: Safety, Production, Efficiency, and Cost. SPEC serves as a practical lens through which to evaluate the full impact of integrity decisions.

Safety: Many registrable items are direct contributors to loss of containment risks. Low-level defects can initiate incidents with significant HSE consequences.

Production: Equipment failures in these items often cause unplanned outages, their proximity to critical systems being one of the reasons.

Efficiency: Poor visibility of item condition or location leads to inefficiencies. When registrable items aren’t accurately documented or easily located, teams spend more time finding the problem than fixing it.

Cost: While individual components may be low in value, the cumulative cost of reactive maintenance, production loss, and extended downtime adds up. A well-managed registry is a relatively low-cost intervention with a disproportionately high return.

This model supports a more holistic view of asset integrity and has been instrumental in reshaping how we prioritise and manage registrable items. But applying a framework is not enough — the tools that support it must also evolve.

Unlocking Value Through Visual Tagging and Technology

"The ability to see, tag, and manage registrable items in their exact spatial context is one of the most powerful developments in offshore integrity management in the last decade. It brings clarity where once there was uncertainty."

Niall Shanks, Integrity Operations Manager

The registration of integrity-critical items has traditionally been a text-based exercise. This approach limits insight, slows decisionmaking, and increases the risk of oversight.

Digital platforms that combine photographic imaging and 3D cloud point capture are changing this. By tying registrable items directly to their visual and spatial context, these technologies transform how asset teams interact with integrity data and offer new levels of clarity. GDi’s framework is built around four interconnected processes to maximise the potential of this solution:

• Identify & Tag - Locate and clearly tag features that require inspection or monitoring.

• Register Key Descriptors - Log essential details like type, location, material, and visual reference into your integrity system.

• Risk Assess - Evaluate the criticality and degradation risk of each feature to prioritise inspections.

• Monitor & Action - Carry out inspections, track changes, and ensure any findings or repairs are linked back to the correct feature.

Additional benefits of this approach include: remote desktop inspection that reduces offshore personnel and enhances safety; improved inspection quality through clearer visual context; better collaboration with shared, up-to-date asset views; smarter prioritisation of high-risk items; and faster turnaround times that support compliance and reduce admin burden.

A Call to Action

To close this gap, the industry must reframe the role that registrable items play in asset integrity and bring them into the centre of the conversation. This requires a few key shifts:

1. Establish Clear Ownership

Assign responsibility for registrable item management within asset teams. Ensure that ownership spans registration, inspection, and ongoing maintenance.

2. Invest in Accurate, Up-to-Date Registries

Move away from static spreadsheets and legacy drawings. Leverage modern datacapture tools to create living registries that reflect the current state of the asset.

3. Prioritise Based on Risk, Not Just Scale

Recognise that size does not equate to impact. A leaking flexible hose or corroded trunnion can have just as much consequence as a vessel failure if not properly managed.

4. Integrate Registrable Items into Integrity Planning

Include them in RBI schemes, performance standards, and turnaround scopes. Ensure they are considered in modifications and decommissioning strategies.

5. Support with Fit-for-Purpose Technology

Use tools that enhance visibility and collaboration to make integrity management more accurate, efficient, and auditable.

The integrity of offshore assets depends as much on the performance of the small as it does on large, high-profile systems. By raising the standard of how we manage registrable items, we not only reduce risk — we improve reliability, efficiency, and long-term cost effectiveness.

Conclusion

Registrable items remain fundamental to the integrity of offshore operations. Technology now gives us the means to address these challenges, but tools alone are not the solution. It will take a shift in culture, ownership, and priority to ensure that small components receive the attention their impact deserves.

By rethinking how we manage registrable items we can drive meaningful improvements across the spectrum of asset performance: from safety and compliance to cost and uptime.

Vision – Digital Asset Management Platform

GDi is committed to supporting operators in the UKCS and globally with the proactive management of registrable items. Leveraging industry-leading visual technologies and a deep understanding of offshore integrity challenges, GDi offers tailored support for identifying, tagging, and maintaining key components across all asset types. GDi Digital Asset Management Platform – Visionempowers operators to build their first visual register or enhance their integrity strategy, with practical, scalable solutions aligned to their safety and performance goals. 

Vulcan Completion Products: Raising industry standards through the power of collaboration

An international leader in next generation creative solutions for the oil and gas completions market has underscored its commitment to raising industry standards, thanks to a new collaboration.

Aberdeenshire-based Vulcan Completion Products has teamed up with Sudelac to offer comprehensive pre-deployment testing and verification, ensuring that float equipment meets the highest safety and performance benchmarks. This proactive approach mitigates risks, enhances operational reliability, and provides peace of mind to oil and gas operators worldwide with the simple mission to ensure the integrity of float equipment before running it downhole.

By researching the status quo and incumbent approaches, and listening carefully to the needs of IOCs, NOCs and major service companies, the Vulcan Completion Products team has gained better understanding of float equipment and cement plug failures due to historic lower cost and/or lower quality equipment choices. The message from experts is clear: the lack of proper verification and testing increases the likelihood of costly operational failures, compromising well integrity and safety.

While an API standard exists for float equipment and cement plugs, adherence has been inconsistent, and Vulcan Completion Products is now leading the charge in the shift toward better equipment testing and verification, thus safeguarding assets, optimising performance, and preventing failures before they occur. Failures in float equipment highlight the urgent need for rigorous testing and adherence to established standards and often occur due to inadequate backpressure resistance or wear after minimal flow exposure. At the rig site, function tests provide a basic assessment of operability, but these are not sufficient to guarantee long-term reliability.

Vulcan Completion Products ensures that all float equipment meets API standards through rigorous testing protocols to ensure real-world performance validation and addresses gaps by offering independent third-party verification that gives clients confidence in their equipment before deployment.

By working together, Vulcan Completion Products and Sudelac will support global clients with testing verification of their float equipment and offer peace of mind prior to running into hole, going beyond conventional QA/QC checks, utilizing advanced testing methodologies to validate equipment integrity under actual field conditions.

Founded in 2010, Sudelac is a UK-headquartered upstream oil and gas service sector business that provides products and services for well construction through to abandonment. Central to the portfolio is the internationally patented FloatCHECKER™ PT which ensures that kit, new and old, is fit for purpose prior to mobilisation. Benefits of non-damaging system include the capacity for high- and low-pressure testing of float equipment post-manufacture and the ability to reduce risk whilst improving stock management and cost control to maximise user confidence.

Since 2023, Vulcan has expanded its workforce by 50% and now employs over 30 people across key international locations including the UK, US, Dubai, Baku, Saudi Arabia, Vietnam and Jakarta. Planned expansion in Africa has, to date, generated good levels of enquiry from the likes of Angola, DRC, Egypt, Gabon, Cameroon and Guinea-Bissau with a clutch of key contracts instrumental in establishing a foothold in this important emerging market.

From the company’s global headquarters at Westhill, Aberdeenshire the team pours more than 200 years of combined experience into delivering the best

design, manufacture, and application of bespoke, innovative, and ground-breaking solutions to a growing customer base all over the world. From centralisation, reamer, and guide shoes to float equipment, cement plugs, collars, and cable protectors VCP has an unmatched record of success, with the emphasis firmly on being a quality service provider who consistently exceeds client expectations. The portfolio is augment by the company’s ISO9001-accredited research and development hub supports ongoing international growth focusing firmly on innovation to empower Vulcan Completion Products to continue leading the market with new products and technological advancements.

Nabors, Corva AI join to advance digital transformation in drilling industry

Nabors Drilling Technologies and Corva AI announce the expansion of their strategic alliance, reinforcing the shared vision to accelerate digital transformation in the drilling industry. Building on the strategic alliance, Nabors and Corva are extending their collaboration into the RigCLOUD® platform to advance drilling intelligence and broaden industry impact.

“RigCLOUD® Powered by Corva” is a fully integrated drilling intelligence solution that is set to combine Nabors’ edge and cloud computing platform with Corva’s industry-leading AI-driven analytics. Leveraging Corva’s Platform-as-a-Service and drilling solutions, Nabors aims to extend its operational reach across diverse data residency jurisdictions and accelerate entry into new markets by strengthening services for E&P customers and third-party drilling contractors.

“The expansion of our existing strategic alliance, integrating the RigCLOUD® ecosystem with Corva, marks a significant next step in our digital strategy.” said Subodh Saxena, Senior Vice President of Canrig and Nabors Drilling Solutions. “By combining RigCLOUD® rig instrumentation and drilling automation apps with Corva’s industryleading AI analytics, we are defining the future of drilling intelligence.”

“We’ve reached a new milestone with Nabors, unifying edge and cloud solutions into a single platform that streamlines workflows and enhances operations across any rig fleet. Together, we’re setting new standards for drilling efficiency,” added Ryan Dawson, Founder and CEO at Corva.

RigCLOUD® Powered by Corva will enhance real-time data processing, predictive insights, and performance optimization, giving operators and contractors the ability to improve decision-making and maximize efficiency. The integration will equip customers with industry-leading tools such as seamless edge-to-cloud integration and drilling intelligence at the rigsite to unlock new opportunities across operations. 

• All-inclusive industrial coworking space

• Low risk flexible short terms to suit your business as it expands or contracts

• Currently 15 Companies from 12 countries

• Remove the complexity and financial risk of running your own industrial facility

• Focus on your business, not your infrastructure

Kronos Pressure Testing: A new way of monitoring and reporting

By David Marshall, Measurement and Offshore Business Development Manager, Intervention Rentals

After more than a decade working offshore across the North Sea and internationally, I’ve seen how innovation can transform not only how we operate - but how effectively we deliver for our clients. At Intervention Rentals, that mindset has driven the development of our latest advancement in pressure testing technology: Kronos.

Kronos is a next-generation digital pressure testing software, designed to replace traditional manual processes with a smarter, faster, and more reliable solution. It delivers real-time data monitoring, automated pass/ fail criteria, and comprehensive digital reporting. Whether offshore or in the workshop, Kronos brings a level of control and clarity that raises the bar for safety, accuracy, and efficiency.

Incorporating the Kronos software into a workshop environment unlocks huge benefits.

It streamlines setup, reduces human error, and provides fully traceable test recordsmaking compliance audits smoother and more transparent. With its user-friendly interface, teams can quickly adapt, improving productivity and minimising downtime. But more than a tool for today, Kronos has been purpose-built for the future.

Our long-term vision for Kronos is to evolve it into a fully integrated digital ecosystem for pressure testing and asset verification. Future updates will introduce enhanced analytics, remote access capabilities, and predictive maintenance features. Cloud-based data storage will enable secure, real-time access from anywhere, supporting faster decisionmaking and multi-site coordination. We’re also focused on modular expansion - so users can customise the system with new sensors and features as their operations evolve.

Equally important is sustainability. Kronos is designed with durability and energy efficiency in mind, aligning with the sector’s wider drive towards low-impact, future-ready solutions. Combined with ongoing training and customer support, our aim is to ensure Kronos not only meets today’s challenges but stays ahead of tomorrow’s.

As the industry continues to embrace digital transformation, solutions like Kronos will become essential. At Intervention Rentals, we’re proud to lead this shift - delivering technology that empowers smarter, safer, and more sustainable operations.

To learn more or arrange a demonstration, get in touch - we’d love to show you what Kronos can do for your business. 

FROM ZERO TO 60: THE TECH THAT REVIVED A NON-PRODUCING WELL

CONVENTIONAL

METHODS BEFORE THOR 0 BOPD AFTER THOR 6 0+ BOPD

A 400-million-barrel field with zero production. Oil too heavy to flow. Rod pumps failed. Cable heaters underperformed.

Deploying THOR at the perforations - a downhole heater delivering targeted in-well heat: reduced viscosity, enabled inflow and transformed the well’s output.

The Result?

Production surged from 0 to over 60 barrels of oil per day, a 30x increase compared to the leading cable heater.

No steam. No surface heating. Just precision-engineered efficiency: cleaner, smarter & cost-effective.

Rotech Subsea: Setting The Standard

Following a record year in 2024, Rotech Subsea, the pioneer and leading provider of Controlled Flow Excavation (CFE) and suspended jet trenching technologies, has continued this momentum into 2025.

Rotech Excavators at 30,000 ft..ABOVE Sea Level

Conveying just how far clients are willing to go to secure its RS excavation systems, Rotech successfully mobilised an entire TRS2 excavation spread, including the tool, a spooler and three 20ft containers, to Taiwan via air at the end of Q1. At the request of a client who insisted on having the best kit on the market, a Boeing 747F was chartered to fly Rotech’s equipment from Prestwick to Taipei, cutting the normal transportation time from six weeks by ship to just a few days.

The ‘Go-To’ Excavation Solution

A non-contact method, Rotech’s systems are designed to excavate with no physical contact to the asset, mitigating the risk of potential damage and providing significant safety benefits. Operating a comprehensive suite of tools including the highest pressure system on the market, customers can benefit from Rotech’s hybrid solution capabilities. This enables Rotech to engineer bespoke solutions to match client specifications, ensuring the correct tool is always selected for the task. This provides the key benefit of improved operational efficiency, delivering narrower trench profiles, increased trenching speeds and the ability to operate in a wider range of soil conditions, reducing vessel time and project risk. With all R&D, engineering and manufacturing operations conducted in-house, Rotech has full control over system quality, reliability and innovation, building great trust with its global client base.

Proven Performance Where Other Methods Fail

Rotech’s ability to consistently deliver proven performance and results was once again demonstrated on a project scope in Taiwan. A tracked vehicle had failed to bury an in-situ cable due to the variable seabed conditions and getting stuck in soft soils.  Deploying its RS2-3 hybrid excavation system, Rotech was able to achieve consistent burial performance despite the varying soils.

200-Day Project Launched

Kicking off a busy season in Taiwan, Rotech Subsea successfully mobilised its TRS2 system for BMS Offshore at the end of March. Strengthening its partnership with the offshore services provider, Rotech will support BMS with seabed preparation services on a major offshore windfarm. Commenting on the commencement of the project, BMS stated “we are proud to strengthen our partnership with Rotech Subsea, driving innovation and operational excellence in offshore operations. Strategic collaborations like these are key to delivering cutting-edge solutions and exceeding client expectations”

Rotech Reviewing Global Positioning

2025 has already seen a shift in sentiment towards one of the offshore wind sectors largest markets, the United States. In what has been the hot topic of conversation within the industry for many months now, President Trump followed through with plans to pause all new federal offshore wind leasing within the US and mandated a review of leasing and permitting practices. With an office in Providence, Rhode Island, and having worked on every major US offshore windfarm to date, Rotech Subsea has been operating in the US offshore wind sector for over five years. Whilst recent events have undoubtedly triggered setbacks for what was forecasted to be a blooming market, Rotech very much believe the market is in ‘pause’ rather than ‘full stop’ mode. In just ten years, the US has

successfully built three major windfarms (with three to follow shortly) which will still require repair and maintenance scopes, something the business is well positioned to support.

Rotech believes that the potential impact on its operations of any reduced demand in offshore wind in the US will be more than offset by two things.

Firstly, the ambitious offshore wind targets set across the globe have long been recognised as being challenging due to the lack of global infrastructure to deliver them. A drop in demand in the US is therefore likely to free up assets to help fill supply chain gaps elsewhere in the world.

Secondly, for the Rotech equipment already deployed in the US there is the option to pivot to oil & gas and decommissioning work in the southern states. With a proven track record in the oil and gas and utilities sectors, the diverse capabilities of Rotech’s systems enable the business to be nimble enough to adapt to market demand, refocusing some of its in-country efforts to benefit from increased activity within these markets.

In Taiwan, the business is also seeing new emerging players entering the market as demand continues to increase. A first-mover in the region with a proven and established track record, Rotech’s reputation and ability to consistently deliver proven results has enabled the business to successfully diversify its client base compared to previous years, a further testament to its previous successes. 

AI – an assistant, not an assassin

Previous waves of technology have gently lapped at the shores of the legal sector: big data, blockchain, metaverse to pick a few from recent years. But when generative AI arrived, it threatened a tsunami for lawyers. Here was a tool that could generate text and replicate style, tone and structure. Following the recent two-year anniversary of the launch of ChatGPT, which forced generative AI into the public consciousness, what has the actual impact on professional services been?

The fear was that AI would replace everything from engineers to artists to lawyers. It could pass exams, give plausible answers to complex questions and draft convincing text. Initially however, the failures were as visible as the successes, with lawyers reprimanded for submitting briefs written by ChatGPT, citing fictitious cases. Answers were generic and sometimes included hallucinations (formerly known as factual errors).

However, in 2024, the solutions started to mature. Existing legal technology providers wove AI into their products, and experiments helped firms to understand the use cases and the pros and cons of this seemingly magical technology.

Has AI transformed the legal sector? Undoubtedly, but perhaps not in the ways that were first envisaged. Perhaps the biggest impact of generative AI has been to show lawyers that technology is a significant part of their future. Interest in legal technology in general has increased and the trojan horse of AI has allowed firms to drive adoption of existing, as well as new, technologies. But rather than replacing humans, it's being used to augment them - performing as an assistant rather than an assassin. Firms started to realise that they could automate some of the tedious work and admin that does not add value, but does consume precious time.

Two years on, the hype has died down and the benefits of generative AI are starting to emerge. Less as a tsunami and more of a steady stream. It is being built into the tools we use already, by Microsoft through Copilot and by vendors of document, case and practice management systems and more. That is, it is making our systems smarter, and allowing our humans to work smarter too.

It's been touted as the saviour of humanity by some and the augur of its demise by others; a calculator for words and an automated mansplaining machine, a work enhancer and a destroyer of jobs. What we can be sure of is that AI has generated a huge amount of investment and a multitude of headlines and think pieces. Want

As organisations identify and exploit the use cases where AI can help them, we will start to see it become part of the furniture. That gives us challenges about how we train our people, how we value the work that we do and how we control quality and risk, but these are all surmountable. In the coming years agentic AI is sure to become the next big thing, allowing AI to not just give answers, but to carry out complex tasks by working with other AIs and systems.

What we can be sure of is that AI is here to stay. Notwithstanding the cost and environmental concerns (both of which are likely to reduce over time), AI will continue to seep into the bedrock of many organisations and to feed new growth, as well as potentially increasing access to justice and making it cheaper to solve certain types of problems. 

Damien Behan is director of innovation and technology at Brodies LLP.

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The UK’s largest innovation funding consultancy

Leyton is an international consulting firm that helps businesses leverage financial non-dilutive incentives to accelerate their growth and achieve long lasting performance.

We simplify your access to these complex incentives. Our combined teams of highly skilled Tax and Technical specialists, enhanced with cutting-edge digital tools developed internally, maximise the financial benefits for any type of business.

Digital Twins: Decarbonising Oil & Gas in a Virtual World

The oil and gas industry remains under a frequent level of significant transformation, with software playing an increasingly vital role in driving energy innovation.

Fromoptimising operations to enhancing safety and sustainability, digital solutions are becoming indispensable for companies looking to thrive in a rapidly evolving energy landscape. Although many innovations have been iterative in nature, building on previous experience and systems, there are also examples of systems which have only recently become a viable option for the Oil & Gas industry – even in their infancy. Among these technologies, Digital Twins are emerging as a powerful tool, offering virtual replicas of physical assets and processes that can unlock substantial benefits in the pursuit of effective decarbonisation.

A Digital Twin is essentially a dynamic, datadriven virtual model. It mirrors real-world assets using sensor data, AI, and cloud computing, providing a continuous, up-to-date representation. This allows operators to gain unprecedented insight into their operations, enabling them to identify inefficiencies and explore decarbonisation strategies in a riskfree environment. The oil and gas industry, under increasing pressure to decarbonise, is turning to innovative technologies like Digital Twins. These virtual replicas of physical assets and processes offer a powerful tool to optimise operations, reduce emissions, and navigate the complex energy transition. In essence, think of a Digital Twin like having a super-smart virtual copy of a real machine or oil rig. This copy gets all the real-time information from the actual thing and can be used to see how

Authored by Brendan Rorrison, Product Owner

it's doing, predict when it might need fixing, or even test out changes without touching the real equipment. It's like a flight simulator for an entire industrial operation.

The requirement for more bleeding edge technology is due to the fact that decarbonisation is a multifaceted challenge for the sector. Companies are striving for net-zero emissions, reducing methane leaks, integrating renewables, and implementing carbon capture technologies. However, technological hurdles, regulatory uncertainties, and economic considerations complicate these efforts and add a multitude of characteristics that are substantially difficult to model and analyse without empirical real world-driven data. Digital Twins offer a pathway to address these challenges head-on through its simulation and recreation of ‘live’ architecture and environments.

By providing real-time energy consumption data, Digital Twins help identify areas for improvement. Operators can simulate process changes, optimise resource allocation, and minimise waste, leading to substantial emission reductions. For instance, refineries have used Digital Twins to significantly reduce steam usage and energy consumption.

Predictive maintenance is another crucial application. By analysing sensor data and predicting equipment failures, Digital Twins prevent unplanned downtime and potential environmental incidents like leaks and spills. This proactive approach enhances safety

and reduces the environmental footprint of operations. Furthermore, Digital Twins are invaluable for asset integrity management, streamlining inspections and turnarounds.

The integration of renewable energy and carbon capture technologies is vital for decarbonisation. Digital Twins facilitate this by simulating the optimal placement and operation of renewable energy assets, like wind turbines on offshore platforms. They also assist in optimising carbon capture systems, ensuring efficient CO2 capture and secure storage.

However, it can be argued that scenario planning is where Digital Twins truly shine. This is because Digital Twins allow companies to model and evaluate the impact of different decarbonisation strategies before implementation. This enables informed decision-making and helps identify the most effective pathways to achieving emission reduction targets.

Industry leaders like BP, Shell, and Equinor have successfully implemented Digital Twins, achieving tangible benefits. BP, for example, is using the technology to calculate real-time carbon intensity at its Clair Ridge facility, aiming for carbon-aware operations globally. Shell has reported a 20% improvement in operational efficiency at its Prelude FLNG facility, thanks to Digital Twins. Equinor leverages the technology to optimise offshore drilling and enhance safety.

Looking ahead, the integration of AI and machine learning will further enhance the predictive capabilities of Digital Twins. More diverse data sources, including environmental and market data, will be incorporated, providing a holistic view of operations. Immersive technologies like AR and VR will improve collaboration and decisionmaking. Lifecycle Digital Twins will offer a comprehensive approach to decarbonisation, from design to decommissioning.

Ultimately, Digital Twins are more than just virtual models; they are powerful tools for driving sustainable change in the oil and gas industry. By enabling data-driven decisionmaking and facilitating the adoption of cleaner technologies, Digital Twins are paving the way for a lower-carbon future. Although the bestcase examples of their use currently sit with some of the biggest players in the industry, this is definitely a technology worth keeping an eye on for the innovation it could offer to the energy sector in the near (and far) future as AI and Internet of Things (IoT) technologies continue to expand into prominence. 

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ADNOC Drilling awarded $1.63bn, five-year integrated drilling services contract

Significant contract award reinforces ADNOC Drilling’s energy services market leadership

ADNOC Drilling Company PJSC announced that it has received a letter of award for a $1.63 billion, five-year contract for Integrated Drilling Services (IDS) from ADNOC Offshore. This landmark award reinforces ADNOC Drilling’s unique position within ADNOC Group and as the region’s leading provider of advanced, integrated energy services, reflects the strength of its strategy to expand its fleet, service offerings and capabilities.

Abdulrahman Abdulla Al Seiari, ADNOC Drilling CEO, said: “We are immensely proud to secure this considerable award, which not only validates our strategic direction but also demonstrates the confidence ADNOC Offshore places in our capabilities. Our IDS offering delivers superior value and innovation, enabling us to play a pivotal role in reshaping the future of energy services in the region. This milestone underscores our commitment to operational excellence, and positions ADNOC Drilling as the partner of choice in an increasingly dynamic and complex energy landscape.

“This five-year award is a strong reflection of ADNOC Drilling’s long-term contracting model, which provides revenue visibility and stability over the contract period. It aligns with our disciplined approach to building a resilient business foundation, capable of generating consistent cash flow and supporting sustainable shareholder returns through the cycle.”

The contract covers the provision of directional drilling, drilling fluids, cementing, wireline logging and tubular running services. The award incorporates advanced engineering and technical support for the effective delivery of extended reach and maximum reservoir wells offshore.

Tayba Al Hashemi, ADNOC Offshore CEO, said: “ADNOC Drilling is a key enabler on our accelerated journey to responsibly meet the world’s growing energy needs. This contract gives us access to their cutting-

Stena DrillMAX wins new contract

Stena Drilling was awarded a campaign with subsidiaries of Shell for the Mobile Offshore Drilling Unit (MODU) Stena DrillMAX. The Shell campaign, which is expected to start in second half of the year, comprises two firm wells and two optional wells.

The Stena DrillMAX is a 6th-generation, harsh environment, dualactivity drillship built for high-efficiency operations. It is capable of drilling in water depths up to 10,000 ft. 

edge capabilities and market-leading end-to-end services, which will maximize efficiency and generate significant value for our shareholders and the UAE.”

This award is a clear endorsement of ADNOC Drilling’s continued commitment to operational excellence, innovation and the adoption of artificial technology (AI) and advanced technologies, underlining its ability to deliver end-to-end solutions that optimize performance while unlocking significant value for its clients. This contract supports the growing Oilfield Services segment, and its economic impact is already included in the current 2025 and 2026 guidance, underpinning the visibility of ADNOC Drilling’s business model and in support for the Company’s financial targets.

As the demand for advanced, high-performance energy solutions increases, the growth of ADNOC Drilling’s IDS portfolio is a cornerstone of the Company’s strategy – enhancing fleet utilization, diversifying revenue streams and accelerating sustainable and long-term growth and returns. The IDS business brings a relatively new and fast-growing revenue stream to ADNOC Drilling, significantly enhancing business resilience and future-proofing the company through the cycles. With its leading market position in IDS in the UAE, ADNOC Drilling is uniquely positioned to capture further growth and deepen its leadership in this high-potential segment. 

Noble wins rig contract extension with Petrobras offshore Colombia

Decision will keep the Noble Discoverer employed in the South American nation until August 2026

Petrobras has so far unlocked in place volumes of more than 6 trillion cubic feet of natural gas with the drilling of the Sirius-1 and Sirius-2 wells in Block GUA-OFF-0 in the Guajira Offshore basin in the Colombian Caribbean Sea.

In a brief post on LinkedIn, Noble informed that Petrobras has exercised an option to keep the semi-submersible drilling rig Noble Discoverer for an additional 390 days in Colombia.

The move extends the contract from July 2025 to August 2026. Financial terms were not disclosed. Noble said Petrobras also has an unpriced option for an additional extension of the Noble Discoverer into the third quarter of 2027.

Petrobras intends to drill at least two more wells in the block this year, including the Buena Sorte-1 wildcat, but the contract extension suggests the oil giant will carry out extra drilling in Colombia.

A drillstem test conducted earlier this year in the Sirius-2 probe at 804 metres of water assessed about 100 metres of reservoir interval, and according to Petrobras demonstrated “good productivity.”

Petrobras already has a plan to begin output from Sirius by the end of the decade via a subsea-to-shore solution through the installation of manifolds in the seabed and with production lines connected to shore.

Petrobras operates the Sirius development with a 44.44% stake and is partnered by Colombia’s Ecopetrol with the remaining 55.56% interest. 

Transocean rig arrives to start major Australian gas exploration campaign

Multi-well programme for several operators starting with ConocoPhillips could boost Australia’s energy security

Transocean’s semi-submersible rig Transocean Equinox has arrived in Australia’s Otway basin ahead of a multi-well campaign that will kick off with a ConocoPhillips-operated exploration campaign in offshore blocks Vic/P79 and T/49P.

Two firm wells are to be drilled this year as phase one of the programme, followed by up to four optional wells (phase two) between 2026 and 2028 on the two permits.

The initial wildcat is scheduled to commence in the third quarter depending on factors including the receipt of all regulatory approvals, and pending weather delays and any operational delays within the four-company operating consortium, said ConocoPhillips’ coventurer ASX-listed 3D Energi.

Seabed surveys in Vic/P79 in commonwealth waters are scheduled to start this month — and expected to take four weeks to complete — ahead of exploration drilling, . The final selection of well locations is yet to be confirmed pending completion of subsurface 3D seismic interpretation studies across the two exploration permits.

The drilling campaign is focusing on lowrisk gas prospects with direct hydrocarbon indicators in the offshore Otway basin, where proximity to existing infrastructure and Australia’s east coast gas market “further enhances the commercial viability of potential finds”, said 3D.

The company added the Otway exploration drilling programme (OEDP) is critical to the future gas needs of southern Australia, given the rapidly declining production from the Bass Strait and forecast shortfall risks from 2028 and structural supply gaps from the following year.

Australia’s independent regulator Nopsema in late February accepted the Environment Plan for ConocoPhillips’ OEDP that proposes up to six exploration wells in water depths ranging from 53 to 200 metres on the Vic/679 and T/49P permits in Commonwealth waters off the coasts of the states of Victoria and Tasmania, respectively.

MODEC wins ExxonMobil Guyana’s Hammerhead FPSO contract

MODEC, Inc. (MODEC) is pleased to announce that it has been awarded a contract by ExxonMobil Guyana Limited (ExxonMobil) Floating Production, Storage, and Offloading (FPSO) vessel for the Hammerhead project.

The contract is a Limited Notice To Proceed (LNTP) by ExxonMobil Guyana, pending necessary government and regulatory approval. Phase one encompasses FrontEnd Engineering and Design (FEED) while phase two covers Engineering, Procurement, Construction, and Installation (EPCI).

The LNTP allows MODEC to start activities related to the FPSO design to ensure the earliest possible project startup in 2029, should the project receive the necessary government approvals. The performance of the second phase (i.e., construction and installation) is subject to government and regulatory approval as well as project sanction by ExxonMobil Guyana Limited and its Stabroek Block co-venturers.

Simultaneously, the Operations and Maintenance Enabling Agreement (OMEA) for MODEC’s Guyana fleet has been established to enable the operations and maintenance of multiple FPSOs under a long-term contractual arrangement.

The Hammerhead FPSO will have the capacity to produce 150,000 barrels of oil per day (BOPD), along with associated gas and water. It will be moored at a water depth of approximately 1,025 meters using a SOFEC Spread Mooring System.

The Hammerhead FPSO will be MODEC’s second for use in Guyana, following the Errea Wittu, which is currently being built for ExxonMobil Guyana’s Uaru project.

MODEC Group President and CEO, Mr. Hirohiko Miyata, expressed his delight for securing the Hammerhead FPSO project.

“We are incredibly honored and excited to have been awarded this contract. It is a testament to our team’s dedication, expertise, and commitment to delivering innovative and reliable offshore floating solutions. We look forward to collaborating closely with ExxonMobil Guyana to ensure the successful delivery of this second FPSO, contributing to the advancement of the offshore energy sector in Guyana.” 

PBR to Commence Well Decommissioning in Sergipe Basin Offshore Brazil

Petrobras S.A. PBR, the Brazilian state-owned energy giant, has stated that Borr Drilling’s jack-up rig, namely Arabia I, has arrived in Brazilian waters to begin decommissioning activities in the Sergipe Basin. The Arabia I jack-up rig secured a fouryear contract from Petrobras in Brazil. The contract includes a four-year option to extend the jack-up rig’s stay with Petrobras. However, the option currently remains unpriced.

The Arabia I jack-up rig was expected to begin its contract with PBR in the first quarter of 2025. The Brazilian energy firm mentioned that the rig arrived in Brazil on April 13, 2025, and is on its way to the Guaricema field in the Sergipe basin to commence well decommissioning tasks. The Guaricema field is a shallow water field located about 9 kilometers off the coast.

Strategic Focus on Decommissioning in Sergipe

The company’s operations in the Guaricema field are part of a broader decommissioning program in the Sergipe region. Petrobras’ strong focus on decommissioning activities in the area, which involve safely shutting down oil and gas facilities that have reached the end of their lifecycle, underscores its commitment to conducting safe and sustainable operations. In its Strategic Business Plan for the 2025-2029 period, PBR has projected an investment of nearly $1.7 billion in the region for the decommissioning of oil and gas infrastructure.

Details of the Arabia I Jack-Up Rig

Borr Drilling’s Arabia I jack-up rig, which was constructed in 2020, boasts a Keppel FELS B Class design. The rig has a maximum drilling depth of up to 30,000 feet and can operate in depths of 400 feet underwater. The rig has the capacity to accommodate 150 people. Its assignment in Brazil includes well intervention

activities involving old oil and natural gas wells. This implies that the oil and natural gas wells that have reached the end of their asset life will be safely deactivated and capped.

The initial campaign for PBR is expected to last for seven months. After that, the rig will move on to work on other wells in the region. Petrobras has mentioned that it plans to decommission approximately 26 units in the Sergipe Basin.

PBR’s Commitment to Safety and Sustainability

PBR has prioritized safely shutting down its operations associated with the assets that are no longer in production while adhering to the highest level of environmental standards and regulations. It has noted that the decommissioning activities conducted in the Sergipe Basin are using the best and most advanced techniques, which are in line with the regulations being followed in the industry at present. This step has been described as a natural progression for the infrastructure in place, as they have been in use for well over 25 years.

The Brazilian energy giant would require the approval of designated authorities like the National Agency of Petroleum, Natural Gas and Biofuels, the federal government agency that oversees the regulations of the oil and gas industry in Brazil, the Brazilian Navy, and IBAMA to execute the required steps associated with the decommissioning process. 

Petrobras to start Guaricema field decommissioning

Petrobras received the PA38 jack-up rig for Guaricema field shallow water well decommissioning about 9 km from the coast of Brazil.

Expected operations are part of Petrobras’ estimated $1.7-billion infrastructure decommissioning program in Sergipe basin as part of the company’s overall 2025-29 strategic and business plan.

The rig will carry out intervention activities for deactivation and plugging. The initial campaign will last about 7 months, with subsequent movement to other wells.

Petrobras is expected to decommission 26 production units in Sergipe. 

More new decommissioning news available @ www.ogv.energy/news/ decommissioning

Genesis in action: Oil platform comes back to life as artificial reef

A new lease on life has been bestowed upon an offshore platform that brought over 120 million barrels of oil to the energy market during its lifetime. This decommissioned oil platform shed its previous skin to transform into an underwater artificial reef, enabling it to live on as a thriving habitat for marine life in the Gulf of America, formerly the U.S. Gulf of Mexico (GoM).

The tale of Genesis, Chevron’s first deepwater platform, dates back to its construction in the late 1990s, when it became the first 705-ft, 28,700ton floating steel spar to house drilling and production facilities.

After coming online in 1999, the oil platform operated half a mile underwater, servicing 20 wellheads arranged on the seafloor. The U.S. energy player decided to retire the giant offshore structure from active service duty in 2019, about 20 years after it produced its first oil.

Decommissioning Genesis required the expertise of a vast number of people and years of effort before the wells were turned off. Chevron has now turned its former platform into an artificial reef for marine life as part of the Louisiana Rigs to Reefs program.

Erin Englert, Chevron’s Regulatory Affairs Advisor, who facilitates programs that transform decommissioned oil and gas platforms into marine life habitats, said: “I’ve seen videos and pictures of the results, and it’s just beautiful. I would love to go down there and visit one.”

Last year, the Genesis’ spar was submerged deep off Louisiana’s coast, just as other decommissioned structures had been before it, since it is not unusual for offshore energy industry components to be repurposed.

This recent project involved turning the spar, or hull, of the former Genesis platform into a gathering spot for creatures like coral, tropical fish, and anemones. As it is believed that marine life is attracted to offshore platforms, U.S. and Louisiana state officials want the structures to continue to provide ecological benefits when decommissioned.

“Fish are reliant upon them as a habitat, It’s rewarding to see them thrive,” emphasized Mike McDonough, Artificial Reef Program Coordinator with the Louisiana Department of Wildlife and Fisheries.

A new life was also breathed into a decommissioned oil field infrastructure offshore Malaysia with a rig-to-reef project, as confirmed by Hibiscus Petroleum, a Malaysian independent oil and gas exploration and production company.

Transforming these huge structures within the offshore energy landscape at the end of their service life into something innovative yet sustainable has become a popular endeavor over the years.

In line with this, Saudi Arabia is paying homage to its oil and gas heritage by pursuing the development of an offshore oil platform-style ‘extreme’ adventure hub as a tourism project in the Arabian Gulf. 

TMC Excellence in North America

Ettienne De Swardt, USA Managing Director

In North America, as around the globe, ATPI’s legacy is built on innovation and exceptional client service, powered by our outstanding team and visionary leadership. As the new Managing Director for the US, I feel honoured to continue that legacy and apply my expertise to help the Group achieve the exciting goals we have mapped out over the coming months.

Servicing the US and the many incredible companies of all sizes that comprise its energy industry, both traditional oil and gas and developing renewable sources, is tantamount to our aims. Already, we have a wealth of clients that, on a day-to-day basis, demonstrate their importance in supporting the nation’s energy infrastructure. We are proud to support them by ensuring that their workforce, whether C-Suite, Onshore personnel, or Offshore crew, has the necessary travel management support to instead focus on their role. By assuming responsibility for how individuals and crews get from A to B and supporting rotation, our inhouse experts handle a significant and timeconsuming administrative burden.

As I step into this new position, aligned with our global energy strategy, as a team we are aiming to keep the momentum going by strengthening existing relationships while creating new ones and exploring how we can further support our customers. The integration of technology and duty of care are among the priorities on my list.

Embracing Technological Innovations

The technology we have at our disposal is one of our USPs and, combined with our knowledge and customer service support, helps us unlock streamlined travel logistics. We have invested significantly in advanced technologies, including AI platforms, to improve operational efficiency internally and the holistic support we provide clients. Like all sectors, digital transformation continues to reshape business travel.

The innovative platforms at our disposal enable dynamic pricing models and personalised travel experiences to help improve travel planning and manage potential disruptions. It’s going to be exciting to share how we are further enhancing our technology offerings in line with industry trends and the desire for methodical and tailored services. With the launch of our crewing online booking technology, CrewHub, and ongoing enhancements to our Duty of Care solutions, we will further strengthen seamless crew

logistics and continue to elevate the level of care and safety we provide to our travellers.

By leveraging data analytics, we can offer clients detailed insights into travel expenditures and patterns. This approach allows for more informed decision-making, cost optimisation, and the development of travel strategies that align with clients' operational goals. Technology is still a tool at our disposal and only works at optimal capacity when united with our experienced and dedicated team.

Duty of Care

In every project and client we support, duty of care is always our number one priority. It brings me immense pride to witness how the team handles delicate situations while placing the customer's wellbeing at the core. In recognition of the complexities of modern travel, we are always looking at ways to enhance our duty of care offerings. Proactive risk assessments, unrivalled 24/7 global support, and our advanced travel tracking systems are just some of the measures taken, each ensuring the safety and wellbeing of clients’ personnel – particularly in challenging environments.

Naturally, shifts in economic and geopolitical conditions, including US trade tariffs and evolving visa requirements, are expected to impact corporate and crew travel. This places new responsibilities on how we look after our customers. Amidst volatile market conditions, we are always closely monitoring changes to ensure smooth visa processing, border entry compliance, and cost-effective travel planning for clients' operations out of and into the US and throughout regions.

Looking Ahead

As the year progresses, in the US and globally, we expect continued advancements in travel technology, increased focus on cost efficiency, and further regulatory changes impacting global mobility. ATPI remains committed to delivering tailored travel solutions, leveraging our expertise and global reach to support energy and marine clients with seamless, efficient, and future-ready travel management.

With a strong foundation built on innovation and customer-centric travel solutions, ATPI is well-positioned to navigate the evolving travel landscape in 2025 and beyond. 