OGV Australia Sept - Drilling + Wells

WHAT'S INSIDE

Welcome to the fifth - and penultimate issue of 2025 - of our OGV Energy Australia magazine on the theme of Drilling, Wells and Pipelines.

We are delighted to showcase STATS Group as our front cover star and feature article. A highly established company in the UK, their feature highlights their incredible expansion across Australia as well as new growth in Asia and New Zealand markets. Their continued success and major project delivery comes from capabilities such as their patent BISEP technology as a leading solution in line stopping for repair and maintenance for critical pipelines across the oil and gas industry in multiple regions and terrains. To find out more, please turn our feature article on page 4.

We are also delighted to provide contributions in this issue from Haztech Solutions, IPI Packers, Destec Engineering, Three60 Energy, Zenith Energy and many more.

There are also comprehensive reviews from regions across the globe as well as the Mining industry here in Australia. You’ll also find insightful articles from Brodies LLP and Leyton, as well as current industry analysis and project updates from Westwood Global Energy Group and the EIC.

Thank you for supporting OGV as we continue our journey in Australia to delivering the latest industry news. Enjoy the issue and see you back for our sixth publication on Marine and Lifting in November!

We hope you are inspired and informed from our third issue of

Growing presence in Australia and the wider Asia Pacific region Pioneering the Energy Transition

STATS Group expects revenues in the Asia Pacific region to more than double in the current year with demand from major oil and gas operators seeking high integrity inline isolation, hot tapping and line stopping technology. In addition to growth in Australia, the company is also investing in asset and increasing local personnel numbers to support an uptick in opportunities in New Zealand, Malaysia, Indonesia, Vietnam and China.

STATS patented double block and bleed / monitored isolation tools offer a comprehensive and efficient solution for the repair and maintenance of critical hydrocarbon pipelines. The ability to perform operations without shutting down the pipeline, providing dual leak-tight seals for enhanced safety and real-time seal monitoring capabilities, position these technologies as valuable assets in the industry.

BISEP®

STATS Group’s patented BISEP (Branch Installed Self-Energised Plug) technology represents a significant advancement in line stopping. Developed over two decades ago to address specific client challenges, the BISEP provides a true double block and bleed isolation through a single full-bore hot tap. Its hydraulically actuated dual elastomer seals surpass the limitations of conventional lip seal technologies, delivering a proven, leaktight, and fail-safe isolation, verified through a multi-stage testing process once deployed into the pipeline.

DNV Type Approval

STATS BISEP is fully certified by DNV to verify that the design criteria satisfies the requirements for Pipeline Isolation Plugs to provide dual seal

and isolation in accordance with Offshore Standards; DNV-OS-F101 (Submarine Pipeline Systems) and recommended Practices; DNV-RP-F113 (Subsea Pipeline Repair) and in compliance with the following code; ASME BPVC Section VIII, Division 2.

Complex Infrastructure Decommissioning

Earlier this year STATS Pipeline Services Pty Ltd was engaged by a leading gas network operator in Western Australia to support the decommissioning and removal of key infrastructure from the historic East Perth Power Station site, helping pave the way for future redevelopment.

STATS safely and successfully executed multiple hot taps and BISEP line stop isolations on 4”, 6”, and 10” pipelines using both standard split tees and spherical tees, including operations that maintained live gas flow via integrated temporary and separate permanent bypass arrangements.

The project was delivered within a suburban residential area, requiring careful planning and execution to minimise disruption and ensure the highest safety standards throughout.

Sam McKinnon, Business Development Manager for STATS, said, “We supplied all fittings and services, with our local team completing full function testing prior to mobilisation from our operational facility in Perth.

“Very proud of the STATS site team and all project partners for the safe and collaborative delivery of this complex scope”.

Provision of Equipment & Training

A leading natural gas transmission and distribution company in New Zealand recently purchased two 8” class 600 BISEP line stop tools along with a range of dual seal slab valves, welded fittings, and other specialist ancillary equipment.

Gareth Campbell, Regional Manager, APAC at STATS Group, commented, “Reaching this milestone and seeing our equipment located in their facility is a proud moment. This upgrade from conventional lip seal line stop equipment means repairs can be completed without disrupting production, with fewer onsite operations and enhanced safety.”

Prior to sending the equipment to New Zealand STATS delivered theoretical and practical hands-on training for selected technicians at STATS global training facility. In addition to the BISEPs and Slab Valves, test fixtures were also supplied which can be used for pre mobilisation and routine training campaigns, providing the client with the ability to continuously develop technician competence.

Challenging Subsea Platform Tie-In

STATS recently achieved another major milestone for the company, successfully completing a complex subsea platform tie-in for a leading Chinese energy company.

STATS deployed their SureTap® subsea hot tapping machine and BISEP line stopping technology at two locations in the East China Sea, isolating a 28” gas pipeline and maintaining uninterrupted production through an integrated 14” bypass whilst also ensuring the safety of the divers. The BISEP is the only line stop technology compliant with IMCA D044, guidelines for isolation and intervention in subsea systems, specifically for diver access. At 70m water depth, a leak-tight midline isolation enabled a critical platform to be connected to an existing high pressure gas pipeline.

Gareth Campbell, commented, “Achieving this complex subsea tie-in without interrupting production is a fantastic milestone for STATS. It showcases our world-class technology, the skill of our team, and the outstanding collaboration with third parties and the client, delivering safely and successfully, even in the most challenging conditions.”

Indonesia First

STATS has completed its first-ever hot tap and BISEP isolation project in Indonesia for an oil and natural gas corporation, executing 12 precision operations across three challenging locations in a single campaign. The scope included six 16” high pressure hot taps to deploy BISEP isolations and six 16” hot taps for a new bypass flow, enabling a seamless pipeline re-route without disrupting production.

The project provided an efficient, commercially significant solution for the client, allowing them to divert their pipeline away from privately owned land. Despite complex rigging requirements and demanding site conditions, STATS’ team demonstrated the resilience of their equipment and the depth of their expertise, completing the work efficiently and safely.

“This landmark achievement for STATS has not only proven the capability of our technology in Indonesia but also sets a new benchmark for high integrity, leak-tight pipeline intervention and isolation projects in the region,” commented Gareth Campbell.

Summary

With major projects successfully delivered in Australia, New Zealand, Malaysia, Indonesia, Vietnam and China, STATS is cementing its position as a trusted partner for high-integrity pipeline intervention and isolation solutions across Asia Pacific.

Supported by patented technologies such as the BISEP and Tecno Plug, full DNV certification, and an expanding local footprint, the company is poised to more than double its regional revenues. With planned further investment and rising demand from leading operators for leak-tight, high-integrity isolation solutions, STATS is also preparing to grow its workforce to support continued expansion. 

integrated bypass maintains production during isolation

Dual Leak-Tight Seals

Double Block & Bleed Isolation

Isolated Pipeline

Monitored Zero-Energy Zone

The BISEP® has an ex tensive track record and provides pioneering double block and bleed isolation while

dual seals provide tested, proven and fully monitored leak-tight isolation, ever y time, any pressure.

Hydraulics Specialist Announces Key Appointments on International Growth Journey

Following the recent announcement that multimillion-dollar investment is planned to uplevel Saturn Fluid Engineering operations in Australia, Dave Mackay has been appointed to a business development role in the region where the naval defence and oil and gas decommissioning sectors will form the nucleus for the company’s growth.

With the Middle East also pinpointed as a key area for expansion, Anas Ahmad has been employed to lead business development while the appointments of UKbased chief financial officer Scott Davidson, global technical lead Mike Smith and Graham Forrest as the Type 26 Frigate project manager to support Saturn’s contract with BAE Systems on their 8 ship UK Type 26 and their Commonwealth Global Combat frigate build programs will further bolster operations at Saturn’s global headquarters in Dundee and Aberdeen 

JMSL Strengthens Leadership and Expands Team to Drive Strategic Growth

JMSL has entered a new phase of strategic growth, building on the recent key appointments to its Advisory Board. These appointments bring additional industry expertise and insight to guide the company’s long-term direction and ensure it remains at the forefront of the energy sector.

Alongside this strengthened leadership, JMSL has established a new entity in the Middle East to expand its presence in key international markets. While pursuing opportunities abroad, the company remains firmly committed to its traditional roots in the UK energy sector, which it has successfully supported since its formation in 2003. JMSL continues to deliver high-quality manpower, project services, and fabrication expertise to its valued clients. 

Pulse Technology Hub Launches in Perth, Driving Innovation and Industry Collaboration

Introducing Pulse Technology Hub, a new center for technology and community now open in the heart of Perth. Founded by industry veterans frustrated by the lack of innovation in Western Australia, Pulse aims to connect industrial operations with cutting-edge, proven technologies.

The hub offers a unique space for showcasing technology and supporting companies looking to expand into the Australian market. By providing expert guidance on everything from local regulations to market strategy, Pulse helps businesses accelerate their growth and profitability. They also offer project planning and delivery support, ensuring clients meet the highest safety and quality standards.

Pulse Technology Hub is more than just a workspace; it’s a dynamic venue for events, creating inspiring experiences that position brands at the forefront of the industry. The grand opening was a success, with senior industrial leaders praising the concept and venue. 

ATPI, the travel partner of choice to the global oil and gas and energy market, has retained its position as an industry leader through updated contracts with two of the largest offshore drilling contractors within the Americas.

Securing both contracts in quick succession, each deal is worth an 8-figure sum per annum and follows established relationships that have been in place for over 10 years. The updated terms for each contract will continue for the next five years.

Following the recent announcement of an 11% sales increase between 2023 and 2024, the confirmation of these two contracts has placed ATPI in a favorable position heading into the end of the US fiscal year. 

Compliance and engineering appointments strengthen STATS Group offering

STATS Group (STATS) has announced two key appointments which bolster their legal and compliance and engineering capabilities.

The pipeline technology company – a leading provider of pressurised pipeline isolation, hot tapping and plugging services to the global energy industry – has appointed Adam Morrice as Legal and Compliance Director based in the company’s Kintore headquarters in Aberdeenshire, Scotland.

Previously Adam held senior positions with Expro as Legal & Contracts Manager and most recently he was Head of Legal at Trojan Energy. As a member of the Executive Committee, he leads the renewal of STATS’ legal, contract, risk and compliance functions, working closely with global and regional leadership teams on contractual oversight, regulatory compliance, policy development and strategy. 

Sasol achieves training milestone with Well Academy

Well Academy recently supported a group of oil and gas professionals on the latest leg of their well control training journey – culminating in the successful completion of the IWCF Well Control in Design and Lifecycle Management course.

The delegates from Sasol began their training pathway in 2017 completing IWCF Drilling Well Control Level 2 and IWCF Well Intervention Pressure Control 2 courses. Well Academy delivered the courses, which provide a solid grounding in essential well control principles, in Johannesburg, South Africa and Temane, Mozambique respectively.

As their development progressed, the individuals advanced to IWCF Drilling Well Control Levels 3 & 4 and IWCF Well Intervention Pressure Control Levels 3 & 4. These courses were delivered both virtually and at Well Academy’s Apeldoorn training centre in the Netherlands 

Our main activities are the supply of downhole equipment and services, specifically – drilling rental tools, tubular and casing running services and workshop pre-assembly services to operators, drilling contractors and service companies. Rental and services within Aus, PNG oil & gas, mining and geothermal

The patented AOGV mechanical isolation system installs a barrier/blind and thus achieves positive isolation between a flange pair on a pressurized system whilst in continuous operation. Unlike hot tapping and line stoppling or alternative isolation technologies, the AOGV allows our customers to safely isolate process segments for inspection, maintenance, or repair without a cashflow shutdown! www.iotgroup.com/worldwide/australia

www.izomax.com Isolation without shutdown.

passionate about disruption and the delivery of wells solutions for lower carbon energy.

PMV (Project Management Vision) is one of the most dynamic and professional post-trade electrical training institutes in Australia. PMV was established as a Registered Training Organisation (RTO) in 2005. Our campuses are located across Australia with head office in Perth, and other campuses in Adelaide, and Karratha. We are committed to providing highquality training programs and have successfully trained more than 8500 students till now.

www.pmv.net.au

For over 120 years, MRS Training & Rescue (formerly known as Mines Rescue Service), has developed specialist skills, experience and knowledge gained from working in difficult and potentially dangerous environments, to effect the rescue and escape of mine workers from underground.

www.mrsl.co.uk

MODS deliver the world’s most intelligent, connected ecosystem of software to ensure industrial assets are managed proactively at every stage of their lifecycles. Our disruptive technologies make a demonstrable, positive impact on business, on people and on the planet.

www.mods.solutions

Australia Energy Review

By Tsvetana Paraskova

Australia’s major energy firms have strengthened their domestic operations and boosted oil and gas production while the federal government raised the clean energy targets.

Woodside and Santos Raise Output, Strengthen Portfolios

Woodside Energy has agreed to assume operatorship of the Bass Strait assets, unlocking potential development of additional gas resources, following an agreement with ExxonMobil Australia.

From completion, Woodside will assume operatorship of the offshore Bass Strait production assets, the Longford Gas Plant, the Long Island Point gas liquids processing facility, and associated pipeline infrastructure. Woodside and ExxonMobil’s equity interests in the assets and current decommissioning plans and provisions remain unchanged.

As operator, Woodside will take on the responsibility for asset planning and execution activities, pursuing a value maximisation strategy that targets further production and reliability improvements, the Australia-based company said.

“As a proudly Australian company, Woodside supports essential domestic energy needs in both Western Australia through the North West Shelf, Pluto and Macedon operations, and on the east coast through its equity participation in Bass Strait,” said Woodside EVP and COO Australia Liz Westcott.

“Taking operatorship of Bass Strait demonstrates Woodside’s continued commitment to meeting Australia’s domestic energy demand while maximising the value of existing infrastructure,” she said.

Woodside also reported quarterly production of 50.1 MMboe (550 Mboe/d) for the second quarter, up by 2 percent compared to the first quarter of this year.

“We delivered strong production of 50 million barrels of oil equivalent for the quarter from our diverse portfolio of high-quality assets. At the same time, ongoing focus on cost control has enabled us to lower our unit production cost guidance for 2025,” Woodside CEO Meg O’Neill said.

“Our announcement in April of a final investment decision to develop the Louisiana LNG Project positions Woodside as a global LNG powerhouse, complementing our established Australian LNG business and enabling us to meet growing global demand from a broader range of customers.”

Woodside also remains focused on delivering the Scarborough Energy Project for gas-toLNG on schedule and budget.

In May, Woodside had the floating production unit hull and topsides for the project connected. Scarborough is now 86 percent complete and on track for first LNG cargo in the second half of 2026, O’Neill said.

Another Australian energy major, Santos, said it had increased second-quarter production

to 22.2 mmboe, up 1 percent compared with the prior quarter.

Western Australia domestic gas production increased by 15 percent compared to the first quarter, driven by successful John Brookes well intervention campaign, steady production from Halyard-2, and strong reliability at Varanus Island, averaging 98 percent for the first half, Santos said in its Q2 results release.

As part of activities for the Moomba Carbon Capture and Storage (CCS) project, Santos executed a non-binding Memorandum of Understanding with the South Australian Government to explore CO2 import and pipeline infrastructure opportunities in support of CCS and low-carbon fuels ambitions in the Cooper Basin.

The Barossa LNG project is around 97 percent complete. The BW Opal FPSO (floating production, storage and offloading) vessel arrived at the Barossa gas field and was successfully hooked up to the subsea infrastructure. Final commissioning activities are progressing to plan. All scopes of work, including the Darwin LNG life extension activities, remain on track for first gas in the third quarter, Santos said.

“We continue to see very strong demand and premia for high heating-value LNG from projects such as Barossa and PNG LNG, as well as for reliable regional supply,” Santos managing director and CEO Kevin Gallagher said.

“Santos’ diversified LNG contract mix provides the flexibility to adapt to evolving market dynamics and capture value-accretive opportunities.”

Australia Raises Renewable Energy Target

While Australian firms look to boost gas production and supply domestically and globally, the federal government in July raised the capacity target in its Capacity Investment Scheme (CIS) from 32 gigawatts (GW) to 40 GW.

The CIS will help deliver the Australian Government’s target of having 82 percent renewable electricity by 2030.

The scheme has so far seen 6 oversubscribed, successful tenders launched, and it is on track to deliver 18 GW of generation and dispatchable storage projects.

The 8-GW capacity increase is set to incentivise investment in projects to deliver an additional 5 GW of storage and 3 GW of renewable power generation by 2030. A 3 GW boost to CIS generation was helped by the competitive nature of the tenders and falling costs of solar, the government said.

The uplift is expected to support investment of around US$13.6 billion (AUS$21 billion) in storage capacity. Investments of nearly US$34 billion (AUS$52 billion) are expected in solar and wind technologies.

More renewable generation and dispatchable projects will create jobs within local communities, support Australian supply chains and manufacturers, and help replace aging coal plants and support rising demand, the government says.

Australia should address the gaps and overlaps in emissions reduction incentives, speed up approvals for clean energy infrastructure, and create a resilience-rating system for all housing to meet its clean energy targets, the interim report of the Productivity Commission inquiry recommends. The Productivity Commission (PC) is the Australian Government’s independent research and advisory body on a range of economic, social, and environmental issues.

The report calls for reforms to the Environment Protection and Biodiversity Conservation Act, which is slowing down vital approvals without effectively protecting the environment. These reforms would introduce national environmental standards, improve regional planning, and set clear rules about engaging with local communities and Aboriginal and Torres Strait Islander people.

The interim report also calls for a greater focus on approvals for priority projects and recommends the Government appoint an independent Clean Energy CoordinatorGeneral to work across government and break through roadblocks. A specialist ‘strike team’ should also be established to ensure priority projects are efficiently assessed.

“Getting to yes or no quicker on priority projects would meaningfully speed up the clean energy transition,” said Commissioner Martin Stokie.

Renewables Surge and Remain Cheapest New-Build Power

The second quarter of 2025 saw record generation output from wind, grid-scale solar, and rooftop solar energy, the Australian Energy Market Operator (AEMO) said in its quarterly report.

Across the National Electricity Market (NEM), a warmer and sunnier start to the June quarter, combined with more new renewable generation capacity, saw record Q2 generation output in wind, up by 31 percent, grid-scale solar (+17 percent), and rooftop solar (+15 percent).

New all-time 30-minute output records were also set, with wind generation reaching 9,472 megawatts (MW) on 25 June, up 13 percent on the previous high. Grid-scale battery discharge surged 119 percent to average 162 MW, driven by 3,116 MW/6,415 MWh of new battery capacity since the end of Q2 2024, the market operator said.

Continued investment in new wind and solar has lifted renewables’ share of generation from 32 percent to 38 percent year-on-year for the quarter, said AEMO Executive General Manager Policy and Corporate Affairs Violette Mouchaileh.

In periods in June, isolated cold conditions and low wind conditions triggered spikes in heating demand and reduced wind generation. This led to a greater reliance on gas-fired generation and batteries to meet evening peak demand, AEMO noted.

“Ongoing investment in gas-fired power remains critical to generate energy during these periods of low wind or solar, or when storage reserves are depleted, and to support growing demand as our power systems transition,” Mouchaileh said.

Renewables remain the lowest-cost newbuild electricity generation technology, while nuclear small modular reactors (SMRs) are the most costly, according to the final 202425 GenCost Report by CSIRO, Australia’s national science agency, in collaboration with the AEMO.

Yet, rising construction costs in Australia and supply chain constraints for some technologies remain a challenge for reducing costs, the report found.

“The latest GenCost report released by the CSIRO today reaffirms the longstanding reality that renewables are the lowest-cost, and most practical option to transition Australia’s energy system,” said Anna Freeman, Clean Energy Council General Manager – Advocacy & Investment.

“The truth remains that renewables remain the lowest cost form of energy, even when taking into account the cost of firming these generation assets, including the costs of storage, transmission, and system security.”

MINING Review

By Tsvetana Paraskova

Australia is looking to bolster its position in critical minerals supply with support to struggling smelters, while mining companies have announced a string of updates on minerals mining projects.

Australia Bails Out Smelters

The federal Albanese Government has said it would invest AUS$57.5 million to protect jobs in Australian smelters as part of a AUS$135 million package with South Australian and Tasmanian Governments. The local governments will invest AUS$55 million and AUS$22.5 million of the total package, respectively.

The announced investment will support the transformation of Nyrstar’s Port Pirie and Hobart smelters into modern facilities capable of producing critical minerals. Nyrstar, a leading manufacturer of zinc, lead and other metals, is owned by commodity trading giant Trafigura.

The combined support package, coupled with investment from the company, will enable Nyrstar to maintain its operations while progressing detailed engineering plans to

potentially rebuild and modernise both smelters and, at the same time, fast track feasibility studies into world-leading critical metals production, the Australian government said.

Through the studies, Nyrstar proposes to explore the potential production of essential critical minerals, including antimony and bismuth at Port Pirie and germanium and indium at Hobart. These critical minerals are considered vital for sectors including defence, clean energy, transport, advanced manufacturing, and high-tech applications.

An immediate focus of the package is to deploy an Antimony Pilot Plant in Port Pirie, which if successful would make Port Pirie the only producer of antimony metal in Australia and one of the few producers globally.

Antimony is essential for the manufacture of semi-conductors found in electronics and defence applications and is used in flame retardant materials.

“Through this transformation, Nyrstar aims to explore possible production of antimony, bismuth, tellurium, germanium and indium, minerals vital to clean energy, defence, and high-tech sectors,” said Australia’s Minister for Industry and Innovation and Minister for Science Tim Ayres.

“Sustainable and competitive smelting capabilities in Australia that can deliver critical minerals projects are part of the Albanese Labor Government’s Future Made in Australia agenda.”

Added Ayres, “There are other critical minerals that we can process here in Australia as a byproduct of the lead and zinc manufacturing processes in Port Pirie and Hobart.”

The Nyrstar Hobart smelter is one of the world’s largest zinc smelters in terms of production volume, focusing on high-value added products for export primarily to Asia.

The Port Pirie plant, for its part, is one of the world’s largest multi-metals smelters, processing and refining lead, silver, zinc fume, copper matte, and by-products such as sulphuric acid - all products that are essential for the renewable energy transition.

Mining Association Warns of Decline in Investment Attractiveness

The Association of Mining and Exploration Companies (AMEC) said that investment attractiveness in Australia has taken a hit this year—for the first time in living memory, no Australian jurisdiction appears in the Top 10 in the ranking of jurisdictions around the world for investment attractiveness. In comparison, the US has four jurisdictions in the Top 10 in the Fraser Institute Survey.

Notably, Western Australia has slipped from 4th to 17th place in the global ranking, the Northern Territory fell from 8th to 38th, Queensland from 13th to 39th, South Australia from 19th to 35th. All Australian jurisdictions gave up a lot of positions in the investment attractiveness ranking.

“As a country and industry that relies heavily on overseas investment to support exploration and the development of new mining projects, we should always pay close attention to significant changes in investor attitudes,” AMEC Chief Executive, Warren Pearce, said.

“Regrettably, many of the concerns raised, reflect what Australian industry has been saying for some time, primarily about increased uncertainty around land access and approvals.”

Still, AMEC notes that both Federal and State Governments have been working with Industry over the last year to address the key issues raised in the survey.

Federally, the Commonwealth has thrown out contentious Nature Positive Reforms –and started again, pursuing improvements to environmental legislation that AMEC hopes will support a simpler and more certain process around land access and approvals for new mining projects.

Meanwhile, AMEC calls for co-existence to unlock productivity and have both mining and renewable energy projects co-exist in Australia. A report by Modifying Factors

commissioned by AMEC reveals mounting tensions between established industries of exploration, mining and agriculture, with the tidal wave of renewable energy projects. All these industries are competing for access to the same land. The report identifies that even with its large territory, Australia would need the equivalent of more than ‘two Australias’ to provide exclusive rights to all current land users. Therefore, co-existence is crucial to ensure continued investments in new mining projects and expansion of renewable energy at the same time, AMEC says.

“Governments need to work together to implement a process that avoids sterilising valuable resources or locking out high-value land use prematurely,” AMEC’s Pearce said.

“Right now, we have many more competing uses for the land, no consistent rules, and established industries that provide the foundational base of our economy, forced to play second fiddle to rapid renewables expansion,” noted Pearce.

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The company is engaging with potential offtake partners to assess commercial payability options, while expanding its network of potential high-value downstream customers across North America, Europe, and Asia, OD6 said.

Global Lithium Resources Limited has announced the successful negotiation and execution of a Native Title Mining Agreement between its wholly owned subsidiary GLR Australia Pty Ltd and the Kakarra Part B Native Title Group for its flagship Manna Lithium Project.

Global Lithium Resources can now accelerate the Manna Project’s other priorities with confidence, including work streams and approvals relevant to the optimisation of the Definitive Feasibility Study, and the Mining Lease application over Manna – all on track for milestone completion prior the end of this year.

Governments need to work together to implement a process that avoids sterilising valuable resources or locking out high-value land use prematurely

“It’s paralysing mining development, sterilising resources and it’s entirely avoidable.”

In company news, Australia’s OD6 Metals Limited has said that Mixed Rare Earth Carbonate (MREC) and Mixed Rare Earth Hydroxide (MREH) products have been produced from heap leach liquor via metallurgical testing conducted by the Australian Nuclear Science and Technology Organisation (ANSTO). This work is the culmination of nine months of testing and refining of the processing flowsheet that has significantly enhanced the processing efficiency and rare earth product quality at the Splinter Rock Rare Earth Project.

OD6’s future product is crucial for hightech applications in defence, electronics, and renewable energy, due to their unique magnetic and electronic properties.

The Manna Lithium Project remains the third largest lithium resource in the prolific Eastern Goldfields region, containing a Mineral Resource of 51.6Mt at 1.0% Li2O.

Arafura Rare Earths Limited has received a nonbinding and conditional letter of interest (LOI) for a potential further investment from Australia’s export credit agency, Export Finance Australia (EFA), to support Arafura’s Nolans Rare Earth Project in the Northern Territory.

As the world’s most advanced ore-to-oxide rare earths project, the Nolans Project will support the development of secure and reliable supply chains with key international partners, Arafura said.

The Nolans Project is also being evaluated by German authorities for potential support, Arafura’s managing director and CEO, Darryl Cuzzubbo, said.

“As highlighted in our June 2025 quarterly, establishing new sectors requires equitable risk sharing between government and industry through direct investment and offtake,” Cuzzubbo added.

“We have an opportunity to establish Australia as a global leader in the rare earths sector, enabling a resilient, independent and diversified supply chain.”

In what could be a breakthrough in rare earths supply, engineers from Monash University in Melbourne have developed a cleaner, more efficient way to extract rare earths from coal fly ash, mine tailings, and even old electronics. The process is called urban mining – recovering valuable materials from things we have already used, instead of digging for more.

Coal fly ash, the powdery waste left behind by burning brown coal, could be the answer to more sustainable procurement of rare earths, according to the engineers at Monash University.

Their method of extraction can recover all 17 rare earth elements with more than 90 percent efficiency, the engineers argue in a scientific paper. That includes the highly sought-after “magne” rare earths such as neodymium and dysprosium, which are key to making the powerful magnets found in electric motors and wind turbines.

One of the major advantages of the novel approach is that coal fly ash, especially the kind produced from brown coal in Victoria, typically does not contain radioactive elements such as thorium or uranium.

Recovering rare earths from coal fly ash alone could yield up to 45,000 tonnes of rare earth metal each year, the Monash University scientists say.

That’s more than twice what Australia produced in 2021, and nearly 30 percent of current global production. That amount of rare earth metal is enough to make the magnets needed for about 15 million electric vehicles, the engineers note. 

APAC Energy Review

By Tsvetana Paraskova

India will lead global oil demand growth and AsiaPacific will be key to refining capacity additions in the coming decades, while India is breaking renewable energy records and many other Asian countries are boosting clean energy development.

India and Asia-Pacific To Drive Oil Demand Growth and Trade

India will lead global oil demand growth through 2050, boosting consumption by 8.2 million barrels per day (bpd) between 2025 and 2050, OPEC said in its annual 2025 World Oil Outlook 2050 report.

Supported by recent policy shifts and an improved economic outlook, global oil demand is set for continued robust growth of 9.6 million bpd over the medium-term period, rising from 103.7 million bpd in 2024 to 113.3 million bpd by 2030. The primary reason for this is strong oil demand growth in developing countries, which is projected to increase by 8.6 million bpd to 2030 and reach 66.7 million bpd. Moreover, OECD oil demand is also set

to increase over the same period, albeit by a much smaller 1 million bpd to reach 46.6 million bpd, OPEC said.

India, Other Asia, the Middle East and Africa are set to be the primary sources of longterm oil demand growth. Combined demand in these four regions is set to increase by 22.4 million bpd between 2024 and 2050, with India alone adding 8.2 million bpd, according to OPEC’s latest estimates.

The Asia-Pacific region will lead new refining capacity in the medium term. OPEC expects around 5.8 million bpd of new refining capacity coming online globally over the medium term. The bulk of this is set to be commissioned in the Asia-Pacific (3.2 million bpd), Africa (1.2 million bpd), and the Middle East (1 million bpd), representing over 90 percent of the global additions out to 2030.

Rystad Energy also reckons that the Middle East and Asia lead global refining capacity expansion.

“The Middle East and Asia are driving global refining growth by focusing on large, integrated mega-refineries that secure energy supplies and meet rapidly rising demand,” Arne Skjaeveland, Vice President, Oil & Gas Research, Rystad Energy, commented on Rystad research in August.

More than 80 percent of Middle Eastern exports are set to be shipped to the AsiaPacific, increasing from 15.2 million bpd in 2024 to 23.5 million bpd in 2050. The trade route between the Middle East and Asia-Pacific is expected to account for 50 percent of the global interregional crude and condensate trade in 2050, according to OPEC.

India Setting Renewable Energy Records

India added a record 22 gigawatts (GW) of renewable energy capacity in the first half of 2025, which was a 57-percent surge from the 14.2 GW installed during the same period last year, Rystad Energy said in new research.

India’s newly-added capacity includes 18.4 GW of solar, 3.5 GW of wind, and 250 megawatts (MW) of bioenergy, which is generated from plant and animal waste.

Today, nearly all new projects are larger and more economically viable, so even though the total number of refineries worldwide has declined, overall refining capacity continues to grow significantly.

“Today, nearly all new projects are larger and more economically viable, so even though the total number of refineries worldwide has declined, overall refining capacity continues to grow significantly.”

Global interregional crude oil and petroleum product trade is also expected to rise significantly, on the back of higher demand in the Asia-Pacific and growing exports from the US, Canada, and the Middle East, OPEC noted in its annual outlook to 2050.

All these additions mark India’s highest-ever capacity expansion in any six-month period, the energy research and business intelligence company said.

The surge was largely driven by developers moving quickly to take advantage of the government’s Interstate Transmission System (ISTS) charge waiver, which begins at 25 percent and increases annually until full implementation by June 2028, significantly lowering project costs and incentivizing developers to act now.

With the jump in renewable capacity additions, India is now inching closer to its goal of having 50 percent of its installed power capacity from clean energy sources, with a total of 234 GW in place, including large hydropower projects.

While this growth is positive from a strict emissions reduction perspective, fossil fuels continue to dominate actual energy consumption in the country, accounting for around 75 percent of electricity generated in the first half of the year from coal, oil, and gasfired plants.

“India is not yet undergoing a true energy transition; instead, it is focusing on building up installed capacity from both conventional and renewable energy sources to ensure energy security,” said Sushma Jaganath, Vice President, Renewables & Power Research, Rystad Energy.

“Without urgent action to improve affordability and sustainability, particularly through grid upgrades and energy storage, coal will remain central to electrification efforts, jeopardizing progress toward India’s net-zero goals.”

Going forward, India will also rely on nuclear power and plans to boost nuclear installed capacity to 100 GW by 2047, up from 9 GW now.

Meanwhile, the solar industry is shining in India, which has just reached 100 GW of solar module manufacturing capacity.

India has achieved a landmark milestone of 100 GW of solar PV module manufacturing capacity enlisted under the Approved List of Models and Manufacturers (ALMM) for Solar PV Modules, the Ministry of New and Renewable Energy said in August.

“This achievement reflects the country’s rapid progress in building a robust and self-reliant solar manufacturing ecosystem, aligned with the national vision of Atmanirbhar Bharat and the global imperative for clean energy transition,” the ministry added.

The landmark achievement supports India’s target of 500 GW non-fossil capacity by 2030, said Pralhad Joshi, Minister of New and Renewable Energy.

Southeast Asia Boosts Renewable Energy

In Southeast Asia, the Philippines broke ground on the Tantangan Solar Power Project, led by Apolaki Seven, Inc., and ib vogt GmbH. The project will deliver clean and renewable energy to the national grid, boasting a total capacity of 99 MWp. The power plant is projected to generate over 150,000 MWh of clean electricity annually, reducing CO2 emissions by an estimated 66,000 tonnes per year and powering more than 62,000 homes.

The project’s Phase 1, with 40 MWAC, was awarded under the Green Energy Auction Program 2 (GEA-2) and is scheduled for completion by 31 December 2026.

The project in Mindanao will reduce reliance on imported fossil fuels, mitigate greenhouse gas emissions, strengthen national

and regional energy security, increase employment and business opportunities for local communities, and infrastructure development in the host municipality.

“This project contributes meaningfully to our goal of increasing the renewable energy share in our power mix to 35% by 2030 and 50% by 2040,” Undersecretary Mylene C. Capongcol said during the groundbreaking ceremony.

Vietnam aims to raise its renewable energy capacity to reduce emissions in the power sector, which currently relies on coal and gasfired plants.

Vietnam’s cumulative renewable power capacity is expected to reach 112.1 GW by 2035, registering a compound annual growth rate (CAGR) of 14.3 percent in the period from 2024, research from GlobalData Energy showed in August.

The government has announced feed-in tariffs (FiTs), its revised Power Development Plan 8 (PDP 8), and other policies for the development of renewable energy in the country. While hydropower potential is almost fully exploited, the expansion potential for wind, solar, and biomass remains high and largely untapped, according to GlobalData.

Another major economy in Southeast Asia, Malaysia, is also betting big on renewable energy to transform its power sector.

As Malaysia has set a target to reduce reliance on fossil fuels in its power sector and boost the share of renewable energy to 40 percent of total installed capacity by 2035, cumulative renewable capacity is forecast to reach 30 GW in 2035, registering a compound annual growth rate (CAGR) of 16.8 percent during 2024-35, according to estimates by GlobalData.

To mitigate escalating dependence on imported fuels, the Malaysian government is promoting the development of renewable energy sources, such as solar and biomass, GlobalData noted in an August report.

The development of power generation from renewable energy sources is facilitated through government grants.

As of July 2025, the share of renewables in Malaysia’s electricity mix has reached 31 percent, driven by large-scale solar and rooftop systems. The next milestone is 40 percent by 2035 and 70 percent by 2050 — an ambitious target, especially considering that the energy sector accounts for 70 percent of the country’s total carbon emissions.

Malaysia will need over US$143 billion in green investments by 2050 to support renewable energy deployment, clean mobility, and energy efficiency, Energy Transition and Water Transformation Minister, Datuk Seri Fadillah Yusof, said at the Malaysia Energy Policy Forum.

UK North Sea Energy Review

By Tsvetana Paraskova

The importance of the UK’s oil and gas resources, the state of decommissioning of the energy infrastructure offshore Britain, and new projects and contracts have featured in the UK North Sea oil and gas sector in recent weeks.

Offshore Energies UK (OEUK) responded to NESO’s Future Energy Scenarios report, which set out four possible pathways for the UK’s energy transition.

Energy efficiency, demand flexibility, infrastructure and energy supply, and switching to low-carbon technologies will be the critical enablers for success in the energy transition, the report said, noting that “Success along the route to 2050 depends on the choices made today.”

OEUK Market Intelligence Manager Ben Ward commented,

“This report makes one thing clear: the UK’s journey to net zero is becoming increasingly challenging, there is a need for an acceleration of the deployment of low-carbon energy sources in partnership with meaningful engagement with the public to shape the way we consume energy in the future.”

The North Sea’s natural gas and emerging carbon capture industry remain essential to powering the country and cutting emissions, according to OEUK.

“Hitting our climate goals is getting harder each year. The UK already has the expertise, experience and world-class supply chains present in existing industries to deliver on the energy transition,” Ward said.

“To achieve our climate goals we need to continue to support our homegrown energy sectors.”

Oil and gas will remain part of the UK’s energy mix “for a long time,” the UK’s Prime Minister Keir Starmer said during a meeting with US President Donald Trump in Scotland at the end of July.

This reinforces the messaging from Offshore Energies UK, the trade body representing a sector that is vital to the UK economy, OEUK said.

“We believe in a mix, and obviously oil and gas will be with us for a very long time, and that’ll be part of the mix, but also wind, solar, increasingly nuclear…” Sir Keir Starmer said.

“As we go forward, the most important thing for the United Kingdom is that we have control of our energy and we have energy independence and security,” the Prime Minister added.

David Whitehouse, Chief Executive of Offshore Energies UK, commented on the PM’s statements,

“It is good to hear this clear recognition from the Prime Minister that the UK will need a diverse energy mix and that oil and gas remain essential to the UK’s energy future. We’ve long said that this is not a choice between renewables or oil and gas – we need both.”

Whitehouse added, “If we are going to use oil and gas, let’s produce it here – responsibly, with lower emissions, and with all the benefits to jobs, taxes and growth that come from homegrown supply.”

The North Sea Transition Authority (NSTA) published its UKCS Decommissioning Cost

and Performance Update 2025 report, which found that the North Sea oil and gas industry is forecast to spend £27 billion on decommissioning between 2023 and 2032.

Decommissioning is a key activity for the UK’s upstream oil and gas sector, with operators spending a record £2.4 billion in this area in 2024. This is clear evidence that operators are dedicating significant resources to cleaning up their legacy.

The sector is in a pivotal 10-year period, with operators estimating they will commit £27 billion to decommissioning between 2023 and 2032 – more than half the total forecast (2025 onwards) cost of fully decommissioning the remaining UKCS scope, which now stands at £44 billion in 2024 constant prices.

This is a £3 billion increase in the estimate through 2032 from last year’s report, showing that all decommissioning activities have become more expensive. The increase is due to multiple factors, including decommissioning work being brought forward, inflation, higher day rates for rigs, and activities exceeding planners’ initial cost estimates.

While several companies are performing admirably and are in the top quartile for efficiency, many are struggling to keep costs under control, NSTA’s report found.

The activity with the greatest potential for cost savings is well plugging and abandonment (P&A), which is set to account for about half of total decommissioning expenditure. It is also the area causing the greatest concern, as too many companies are delaying well P&A work, NSTA said.

A backlog of more than 500 wells which missed their original decommissioning deadline has built up, while more than 1,000 wells will be due for P&A between 2026 and 2030.

“The supply chain should be able to count on well P&A as a reliable revenue stream which keeps them anchored in the basin until more service companies can transfer their skills to energy transition projects, such as carbon storage, which are now starting to materialise and create opportunities,” NSTA said.

Together with the decommissioning cost update, NSTA warned that operators must immediately start tackling their backlog of wells that are already due for decommissioning to stop rigs leaving the North Sea and prevent billions of pounds of additional costs for themselves and taxpayers.

“Operators face higher costs if they continue to keep the supply chain waiting for work, causing further reductions in rig availability as the rig -owners seek opportunities overseas,” the industry regulator said.

“They also risk fines as last year the NSTA opened its first investigations into missed deadlines – and more could follow.”

Pauline Innes, NSTA Director of Supply Chain and Decommissioning, said,

“The stark reality is that operators are running out of time to get to grips with the backlog as more contractors consider taking their rigs abroad, which damages the supply chain’s ability to meet demand and remain cost competitive. We need operators to rise to the challenge and use the supply chain before they lose it.”

UK ENERGY REVIEW

group has been renamed NEO NEXT and becomes one of the largest producers on the UK Continental Shelf. The joint venture is owned by Repsol E&P Group with 45 percent and NEO UK with 55 percent, with a projected 2025 production of approximately 130,000 barrels of oil equivalent per day (boe/d).

“Our strategy can be summarised as “Resilience, Yield and Growth”: the combined company has much more scale and diversity and opportunities for cost consolidation and portfolio high-grading giving resilience despite the tough conditions in the UK,” said John Knight, Executive Chair of NEO NEXT.

The stark reality is that operators are running out of time to get to grips with the backlog as more contractors consider taking their rigs abroad, which damages the supply chain’s ability to meet demand and remain cost competitive

Separately, NSTA fined Chrysaor £150,000 for vent breaches at the Armada hub in the Central North Sea in 2022.

Chrysaor, which was acquired by Harbour Energy in 2021, blamed the breach on high winds preventing it from relighting the flare on the Armada platform which is 132 nautical miles East of Aberdeen.

In total, Chrysaor vented 370.046 tonnes at Armada from 1 January 2022 to 31 December 2022, exceeding its consent by 145.566 tonnes, or almost 65 percent.

“Reducing the emission of harmful greenhouse gases is vital, and the NSTA will continue to support industry in its efforts to reach net zero by 2050,” said Jane de Lozey, NSTA Director of Regulation.

“In the few cases where companies fail to comply with requirements, the NSTA will not hesitate in applying tough sanctions.”

NSTA will enhance transparency of company specific information in new policy following a consultation launched in 2024. The policy will see companies named when an investigation is opened into a suspected breach, such as exceeding production or flaring and venting consents or failure to decommission.

Previously companies were only named once a sanction was given. A decision has been made to publish names earlier as it was decided it was in both public and sector interest, NSTA said.

In company news, Repsol UK has completed the strategic merger with NEO Energy. The combined

“This company will also be very well positioned to choose both organic and inorganic growth. We will certainly look to be making more value accretive acquisitions.”

Serica Energy said in early August it continues to make progress on advancing future production opportunities. Subsea tie-in work on Serica’s 100-percent operated Belinda field is progressing well, and this new field will come onstream at the start of 2026.

Well-Safe Solutions has been awarded a multi-year contract by EnQuest. The firm scope, expected to generate revenue in excess of $45 million, will be executed using the Well-Safe Defender and consists of a minimum of 100 days of activity in 2026 and a minimum of 130 days in 2027.

The contract also includes options for further activity between 2028 and 2034, creating a multiyear strategic partnership and securing vital supply chain resources in the North Sea well into the next decade, Well-Safe Solutions said.

Shelf Drilling’s North Sea subsidiary has secured a new contract for its premium jack-up rig, Shelf Drilling Fortress, for operations in the UK Continental Shelf. The contract is for one firm well with an estimated duration of three months, and a total value of approximately $12 million. Operations are expected to commence in late August or early September 2025. The rig most recently concluded a contract in the UK in May 2025. 

Europe Energy Review

By Tsvetana Paraskova

The official opening of Norway’s new Arctic oilfield, oil and gas discoveries and development plans, and the UK’s offshore wind allocation round featured in Europe’s energy sector in the past few weeks

Oil & Gas

The Johan Castberg field, Norway’s northernmost oilfield, was officially opened in early August by Norway’s Minister of Energy, Terje Aasland.

The field, which started up earlier this year, already produces 220,000 barrels of oil per day. Production is expected to continue for at least 30 years, field operator Equinor said.

The new field “creates great value and ripple effects and is important for Norway’s role as a reliable, long-term energy supplier,” the company added.

“This is a milestone for the petroleum industry in the Barents Sea. With Castberg on stream, the Barents Sea now has both our second largest producing oil field, our second largest gas field and the largest discovery being considered for development,” Aasland said in his speech to the FPSO crew right after the opening.

Kjetil Hove, Equinor’s executive vice president for Exploration & Production Norway, said, “We are well underway and have already made new discoveries in the area.”

Less than three months after coming on stream the Johan Castberg field was producing at peak capacity of 220,000 barrels of oil per day. Every three or four days, cargoes depart from Johan Castberg.

Vår Energi and its partners have made a gas and condensate discovery in the Vidsyn prospect in the Norwegian Sea. Preliminary estimates indicate that the size of the discovery is 25-40 million barrels of oil equivalent.

The licensees will now assess the discovery together with prospects in the area for a potential development tied back to existing infrastructure, the Norwegian Offshore Directorate said.

The Vidsyn discovery is Vår Energi’s third commercial exploration success so far this year.

The recent Goliat Ridge discoveries are being matured as a fast-track subsea development with flexibility to include potential future discoveries, and two appraisal wells are planned in the Goliat Ridge later this year, Goliat North and Zagato North, Vår Energi said.

The company is progressing around 30 early-phase projects accounting for net 2C contingent resources of around 600 mmboe and expects to sanction over 10 projects during 2025. Four projects have been sanctioned year to date, including Balder Phase VI, a fast-track development operated by Vår Energi that will contribute with high value production through the Jotun FPSO already in late 2026. Fram Sør, a subsea tieback development to Troll C, took a final investment decision in the second quarter, developing 116 mmboe gross resources, Vår Energi said.

TechnipFMC has been awarded a significant integrated Engineering, Procurement, Construction, and Installation contract by Equinor for its Heidrun extension project in the Norwegian North Sea.

For TechnipFMC, a “significant” contract is between $75 million and $250 million.

Energy data and intelligence provider TGS, in collaboration with Axxis Multi-client AS and Viridien, have announced the successful completion of the final imaging of OMEGA Merge, to deliver a single, seamless, and unified high-quality dataset across the Heimdal Terrace, Utsira, and Sleipner Ocean Bottom Node (OBN) multi-client surveys.

Spanning a total area of 3,700 square kilometres from the deployment of over 250,000 nodes and 9.5 million shots, OMEGA Merge is the largest continuous OBN dataset on the Norwegian Continental Shelf, TGS said. Energean and its partner INA – INDUSTRIJA NAFTE d.d. have taken Final Investment Decision (FID) for the development of the Irena gas field offshore Croatia. Energean has a 70 percent working interest in the project. The development plan is for a single platform tie-back to the existing infrastructure at the Izabela field. First gas from the Irena field is expected in the first half of 2027.

“The decision to invest in the development of the Irena gas field is another important step in advancing our strategy of strengthening domestic oil and gas production and ensuring Croatia’s long-term energy security,” Josip Bubnić, Operating Director of Exploration and Production at INA, said.

Low-Carbon Energy

Offshore Energies UK (OEUK) has proposed key reforms to accelerate offshore wind generation following the government’s publication of its Review of Electricity Market Arrangements (REMA).

The decision to take a national approach to pricing will encourage more wind energy investment to help the government hit its Clean Power 2030 targets and boost growth in the critical offshore energy supply chain, OEUK says.

OEUK’s analysis shows that to meet the goal of 95 percent clean power by 2030, the UK must deliver half of this target from offshore wind. This means at least 43 gigawatts (GW) of offshore wind capacity must be installed by 2030, but current projections fall short at just 35 GW. The next three Contacts for Difference

(CfD) rounds must therefore secure an additional 20 GW—equivalent to powering around 15 million homes, according to OEUK.

OEUK welcomed the government’s reforms to the CfD scheme or Allocation Round 7 for offshore wind.

“This new and pragmatic approach to planning, timelines and budgets is important for making Allocation Round 7 (AR7) a success,” said OEUK’s wind and renewables manager, Thibaut Cheret.

“It will enable fixed-bottom offshore wind projects without finalised planning permission to enter this year’s AR7 Contracts for Difference auction. OEUK is pleased the UK government has also followed our recommendations to expand Contracts for Difference (CfD) from 15 to 20 years to unlock investment and reduce cost to consumers.”

To get to the Clean Power 2030 goals, OEUK believes it’s critical the AR7 raises 8.4 GW of offshore wind capacity, which depends on working in partnership with industry.

The UK Government has shortlisted six projects to start negotiations to join the HyNet carbon capture cluster in the North West. These are Connah’s Quay Low Carbon Power, Essar Energy Transition Industrial Carbon Capture (EET ICC), Hydrogen Production Plant 2 (HPP2), Ince Bioenergy with Carbon Capture and Storage (InBECCS), Parc Adfer Energy from Waste Industrial Carbon Capture Project, and Silver Birch.

OEUK head of energy policy Enrique Cornejo, commented, “If we are to hit the UK’s net zero targets and keep our industries thriving, CCUS projects like this must move from plans to delivery much faster.”

Energy technology and oilfield services group SLB has been awarded a technologies and services contract for carbon storage site development in the North Sea by the Northern Endurance Partnership (NEP), an incorporated joint venture between bp, Equinor, and TotalEnergies.

NEP is developing onshore and offshore infrastructure needed to transport CO2 from carbon capture projects across Teesside and the Humber — collectively known as the East

Coast Cluster — to secure storage under the North Sea.

The project scope for SLB includes drilling, measurement, cementing, fluids, completions, wireline, and pumping services.

Another major energy services provider, Halliburton, has also been awarded a contract by the Northern Endurance Partnership (NEP)—to provide completions and downhole monitoring services for the carbon capture and storage (CCS) system.

Halliburton will manufacture and deliver the majority of the equipment required for this project from its UK completion manufacturing facility in Arbroath.

Statkraft, Europe’s largest generator of renewable energy, is to take forward plans for its Shetland Hydrogen Project 2, after agreeing a lease on a site owned by Shetland Islands Council.

in areas including Scotland, Devon, Greater Manchester, and Wales.

The Cydnerth project, which will support the expansion of the Morlais tidal energy scheme, has moved into its construction phase as work has begun on-site at Parc Cybi, Holyhead to strengthen the grid infrastructure for Morlais, a flagship tidal energy project run by local social enterprise, Menter Môn Morlais Ltd.

Backed by the North Wales Growth Deal and funding from both the Welsh and UK Governments, the £16-million Cydnerth project will future-proof Morlais by increasing its grid capacity from 18 MW to an eventual 240 MW.

This is an important and welcome step toward realising the full potential of Ynys Môn’s tidal resources and establishing the area as a hub for sustainable energy

Shetland Islands Council has settled a lease with Statkraft, which plans to build a green hydrogen hub and ammonia production adjacent to the disused Scatsta Airport.

The proposed scheme is an electrolytic hydrogen to green ammonia production facility of up to 400 MW, on land adjacent to the disused Scatsta Airport which is near the existing Sullom Voe Oil Terminal and Shetland Gas Plant.

Pulse Clean Energy has secured a £220 million green finance deal from a consortium of six international banks, marking one of the largest financings in the UK for battery storage infrastructure. This green financing will facilitate the construction of six ready-tobuild battery energy storage system (BESS) sites, including the conversion of existing diesel sites to BESS assets. It will also support the ongoing funding of nine sites already in operation or in late stage construction. These sites are strategically located across the UK

“This is an important and welcome step toward realising the full potential of Ynys Môn’s tidal resources and establishing the area as a hub for sustainable energy,” Andy Billcliff, Chief Executive of Menter Môn Morlais Ltd, commented.

The European Commission has approved an 11-billion-euro French scheme to support offshore wind energy in line with the objectives of the Clean Industrial Deal.

The measure will support the construction and operation of three floating offshore wind farms: one in the sea off the coast of Southern Brittany and two others in the Mediterranean Sea. Each windfarm is expected to have a capacity of around 500 MW, and to generate electricity equivalent to the annual consumption of 450,000 French households.

This measure will contribute to France’s transition towards a net-zero economy and reaching the renewable energy target set at EU level for 2030, the Commission said. The scheme was approved under the Clean Industrial Deal State Aid Framework (CISAF) adopted by the Commission on 25 June 2025. 

Middle East Energy Review

By Tsvetana Paraskova

The OPEC+ group plans to complete the 2.2 million barrels per day production cuts in September, earnings at Saudi Aramco were hit by the lower oil prices in the second quarter, but the world’s top crude oil exporter is bullish on global oil demand in the second half of the year.

The OPEC+ allies reaffirmed their “commitment to market stability on current healthy oil market fundamentals and steady global economic outlook,” OPEC said.

“The phase-out of the additional voluntary production adjustments may be paused or reversed subject to evolving market conditions. This flexibility will allow the group to continue to support oil market stability.”

Granted, the actual increase is likely to be lower than the headline figures suggest – as in previous months – due to the producers that are foregoing large output hikes to compensate for previous overproduction, such as Iraq, OPEC’s second-largest producer, for example.

The eight OPEC+ countries will continue to hold monthly meetings to review market conditions, conformity, and compensation.

With the output increase in September, OPEC+ will have unwound the biggest layer of cuts in recent years.

One final layer, of 1.66 million bpd, remains to be rolled back. Currently, OPEC+ plans to do so by the end of 2026.

However, if markets tighten due to sanctions, penalties, or additional crackdowns on Russian and Iranian oil exports, OPEC+ could step up and unroll these cuts sooner than expected, analysts say.

“We believe the group is finished with its supply hikes, as we move out of the stronger summer demand period and inventories start to rise,” ING commodities analysts said after OPEC+ announced the decision in early August.

“However, much also depends on what happens to Russian oil flows.”

Middle East Set To Become Second-Biggest Gas Producing Region

The Middle East is set to surpass Asia to become the world’s second-largest gas producer in 2025, ranking only behind North America, Rystad Energy said in new research and analysis.

Natural gas production in the Middle East has jumped by about 15 percent since 2020, and the future growth underscores the determination of regional producers to monetize gas reserves and develop export potential to meet global demand, the independent research and energy intelligence firm said.

The Middle East currently produces about 70 billion cubic feet per day (Bcfd) of gas. This is expected to jump by 30 percent by 2030 and 34 percent by 2035 thanks to significant developments in Saudi Arabia, Iran, Qatar, Oman, and the UAE. By 2030, the region will add another 20 Bcfd, equivalent to half

These are some of the most recent themes in the Middle East oil and gas sector, which also include rising investment in Oman’s oil and gas sector and the UAE’s ADNOC Drilling reporting record revenues and profit.

OPEC+ Proceeds with Output Hikes

The OPEC+ alliance decided in early August to increase their collective production in September by 547,000 barrels per day (bpd).

The eight countries implementing the 2.2-million-bpd cut – Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman – will have completed the rollback of all these output reductions in September.

of Europe’s entire gas demand as of today, Rystad Energy reckons.

This outlook hinges on Brent oil prices holding at $70 per barrel and oil-indexed gas prices hovering at the range of $7-9 per million British thermal units (MMBtu). If prices fall below $6 per MMBtu, new projects could be delayed, and expected volume growth by 2030 could slow, depending on the severity and duration of the price decline.

“About half of the 20 Bcfd new supply will meet rising domestic demand, particularly from industrial users, while the rest will be available for export,” said Mrinal Bhardwaj, Senior Analyst, Upstream Research, Rystad Energy.

“As more long-term gas contracts are signed and export volumes rise, the Middle East is on track to become a key energy hub for countries seeking stable and dependable sources of natural gas.”

Oil & Gas Drive Foreign Direct Investment in Oman

Foreign Direct Investment (FDI) in Oman surged to approximately $79.5 billion by the end of the first quarter of 2025, with inflows reaching $13.6 billion, up from $10.7 billion during the same period in 2024, preliminary figures released by the National Centre for Statistics and Information (NCSI) showed.

Upstream oil and gas remained the largest recipient of FDI, attracting $64.1 billion, or 81 percent of total investment, with quarterly inflows of $12.5 billion, according to the data.

The United Kingdom remained the largest FDI contributor, accounting for 51 percent of total FDI at $40.5 billion, followed by the United States with $20.3 billion, and Kuwait with $3.2 billion.

Saudi Aramco Books Profit Drop, Bets on H1 Oil Demand Growth

Despite higher oil production in line with the OPEC+ deal, Saudi Aramco booked a 19-percent drop in second-quarter earnings as

MIDDLE EAST ENERGY REVIEW

lower oil prices weighed on liquids realizations. Aramco reported a net income attributable to shareholders of $22.85 billion for the second quarter, down by 19 percent from the same period last year. The income also fell compared to the first quarter as Aramco’s average realized crude price was $66.70 per barrel in April to June, down from $76.30 in the first quarter and from $85.70 a barrel for the second quarter of last year.

The world’s biggest oil firm, however, remains bullish on the oil market in the second half of the year and in the long term.

ADNOC Drilling Company PJSC, said it delivered record-breaking performance across revenue, EBITDA, and net profit while maintaining strong momentum in shareholder returns and delivering regional expansion.

For the first half of 2025, ADNOC Drilling booked a record net profit of $692 million, up by 21 percent from the same period last year. Revenues jumped by 30 percent to $2.37 billion, EBITDA rose by 19 percent to $1.08 billion, and free cash flow soared by 67 percent to $727 million.

Market fundamentals remain strong and we anticipate oil demand in the second half of 2025 to be more than two million barrels per day higher than the first half

“Market fundamentals remain strong and we anticipate oil demand in the second half of 2025 to be more than two million barrels per day higher than the first half,” Aramco president and CEO Amin Nasser said.

“Our long-term strategy is consistent with our belief that hydrocarbons will continue to play a vital role in global energy and chemicals markets, and we are ready to play our part in meeting customer demand over the short and the long term.”

In the United Arab Emirates, Abu Dhabi’s ADNOC has announced its intention to transfer its 24.9 percent shareholding in OMV AG to XRG, its wholly-owned international investment company focused on gas, chemicals, and green energy.

ADNOC Drilling is expanding regionally in Oman and Kuwait, while Turnwell, ADNOC Drilling’s unconventional drilling specialist, reached new operational milestones in the second quarter of 2025 as it expanded its presence across the UAE’s onshore unconventional basins.

ADNOC Drilling also continues to embed AI, automation, and advanced analytics across its operations to enhance efficiency, safety, and reliability.

“ADNOC Drilling has consistently demonstrated its ability to grow in any phase of the energy cycle,” said Abdulla Ateya Al Messabi, ADNOC Drilling CEO.

“With high and visible cash flows, growing earnings and strong visibility of future returns, we remain confident in our ability to continue delivering long-term value to our shareholders.” 

Adnoc

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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

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.

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MINA WEST GAS FIELD

The operating joint venture comprising of and KUFPEC announced a financial investment decision for the field development.

The Mina West gas field, located in water depths of approximately 250 metres, will be developed as a subsea tie-back to the existing infrastructure of West Delta Deep Marine (WDDM).

SHENANDOAH SOUTH SUBSEA TIE-BACK

A final investment decision has been announced with first oil expected to be reach in Q2 2028. The discovery which is estimated to hold around 74 million barrels of oil equivalent (P50 resources) will see the drilling and completion of two production wells. The wells will be tied back to the Shenandoah FPU using a 3.2km flowline and a dedicated riser.

AZERBAIJAN

SHAH DENIZ COMPRESSION PROJECT

SOCAR-KBR LLC has secured a contract to provide detailed engineering design solutions and procurement services for the SDC gas field project. The company was also awarded a contract to support the BP operated Sangachal Terminal Electrification (STEL) Project.

MERPATI FIELD DEVELOPMENT

Following the award of a Production Sharing Agreement for Block C in Brunei, EnQuest will now look to form a JV with Brunei Energy Exploration Sdn Bhd. Once established the JV will focus on the development plan for Merpati with the aim of reaching a final investment decision in 2027, and starting gas production in 2029.

GAJAJEIRA GAS AND CONDENSATE

Azule Energy has announced a gas discovery through the Gajajeira-01 exploration well, drilled by the Valaris 144 jack-up rig.

Preliminary estimated resources are about 1Tcf of gas and 100MMboe of condensate. Drilling operations will continue on the well targeting the Lower Oligocene LO300 interval.

AKKAS FIELD REDEVELOPMENT

Iraq has signed a new agreement with SLB to increase the production at the Akkas gas field in Al-Anbar province.

Schlumberger will be drilling new wells to achieve an initial production rate of 100 MMcf/d, and targeting a longer term production rate of 400MMcf/d.

SABRATHA GAS

PROJECT – A AND E

STRUCTURES

INTEGRATED FIELD DEVELOPMENT

A project management services contract has been awarded to Hill International. The scope of work includes detailed design to approve engineering on new infrastructure and upgrades, fabrication, installation and hook-up, and testing and commissioning of the onshore facilities.

HEIDRUN SUBSEA EXTENSION

TechnipFMC has been awarded an iEPCI contract worth between USD$75m and USD$250m for the project. The company previously had been awarded and conducted an iFEED study. The field development will involve the installation of two new production templates with eight slots, and the drilling of five new wells; two production wells and three injection wells, plus a new umbilical to Heidrun.

BLOCK 15 REDEVELOPMENT

Oceaneering has been awarded a three-year contract to provide services in support of offshore operations in the block.

Under the agreement, the company will provide ROVs, ROV tooling, intervention workover control systems (IWOCS), satellite communication systems, subsea inspection, hydrate remediation, and engineering services.

WOLIN EAST OIL AND GAS DISCOVERY

CEPetroleum has announced an oil and gas discovery via the Wolin East 1 well drilled utilising the Noble Resolve jack-up rig. The project’s estimated to contain 200MMboe. The operator will now advance conceptual infrastructure development studies on the discovery which is located in water depths of 9.5 metres.

IRENA GAS FIELD

The operator has taken a final investment decision on the 30.5 Bcf gas field. The field is to be developed as a single platform tie-back to the existing infrastructure at Izabela field. First gas is expected in the first half of 2027.

VIETNAM GAS PROJECT – BLOCK B

A consortium of Yinson and PTSC has been awarded the contract to provide an FSO for the project. The contract includes a firm period of 14 years with a potential extension of up to 9 years. The FSO is expected to be a newbuild, double-hull, turretmoored unit to be installed in a water depth of 80m. The FSO will have a storage capacity of 350,000 barrels of condensate.

Drilling, Wells & Pipelines: Australia’s Energy Sector Focuses on New Gas Supply Amid

Global Uncertainty

Upstream companies are focusing their exploration efforts on lower-cost and lower-risk infrastructure-led exploration prospects amid volatile commodity prices and many uncertainties about the global economy this year.

In Australia, local and foreign energy companies have acknowledged the need for additional domestic gas supply and are looking to advance drilling campaigns and projects off Australia’s coasts. Companies including the biggest Australia-listed oil and gas firms, Santos and Woodside Energy, call for increased investment in gas supply and certainty in regulations to back the Government’s Future Gas Strategy.

Lower-Risk Near-Field Exploration

Volatile commodity prices and tightened budgets have prompted many exploration and production (E&P) companies to focus on low-risk, low-cost near field or infrastructureled exploration (ILX) prospects instead of expensive, high-risk exploration plays, independent research and energy intelligence company Rystad Energy said in a recent report.

Norway, Indonesia, and the US will emerge as ILX hotspots this year, according to Rystad Energy analysis.

Lower-Risk Near-Field Exploration

The largest Australian oil and gas producers are calling for increased investments in new domestic gas supply to meet energy needs, maintain Australia’s resource advantage, and supply LNG to the growing global market.

“Australia needs to develop more of its own gas supply,” Kevin Gallagher, CEO at Santos, said at the 2025 AEP Conference & Exhibition.

“Affordable energy is quite simply the lynchpin of national success. Without it, we pay more for everything,” Gallagher said.

The energy transition is slower than initially expected as energy demand continues to grow, the executive added, but noted that Australia is “exceptionally well-positioned” to lead in carbon capture and storage (CCS).

“We have world-class geological storage basins and we have the project experience,” Santos’ chief executive said.

In conclusion, Gallagher stated, “The world has an insatiable appetite for energy. And it will need all forms of energy to feed that appetite.”

Australian producers now have the opportunity to take real actions that deliver the Government’s Future Gas Strategy, Woodside CEO Meg O’Neill said in an address at the same conference this year.

However, forecasts of looming supply shortfalls on both the east and west coasts and weakened investor confidence in investing in new supply could put Australia’s energy leadership at risk, O’Neill said.

“Certainty around Australia’s energy and climate policies, environmental regulation and timely approvals is critical to driving investment,” the executive added.

“I am encouraged by evidence – including the Government’s Future Gas Strategy –that policymakers are increasingly willing to recognise and speak up for the critical importance of natural gas, including as the stabilising partner to higher levels of renewables and as a lower emissions source of power than coal,” O’Neill noted.

Woodside’s boss called for exploration to resume in earnest in Australia. This would begin with regular offshore acreage licensing rounds, and clear regulations around the well-proven and safe technology of seismic surveys.

“We must get exploration going now to ensure the energy future of the 2030s and 2040s is secure,” O’Neill said.

Lower-Risk Near-Field Exploration

Companies have approved a new drilling exploration programme offshore Victoria off the south-eastern coast of Australia.

ConocoPhillips and 3D Energi confirmed in early July the final well locations, drilling sequence, and anticipated timing for the upcoming Phase 1 Otway Exploration Drilling Program within VIC/P79 exploration permit. 3D Energi has a 20-percent participating interest in VIC/P79 and T/49P exploration permits, Otway Basin. ConocoPhillips Australia is the operator of the exploration permit and announced plans to explore for natural gas in the Otway basin to supply the domestic market.

DRILLING, WELLS & PIPELINES

The Transocean Equinox rig is scheduled to start work for ConocoPhillips Australia in September 2025, weather and operational conditions permitting. The rig will drill two wells in the Otway Basin before the end of the year as part of the Otway Exploration Drilling Program.

The first well to be drilled is called Essington-1, approximately 55 km offshore from Port Campbell.

Anchors and mooring chains will be deployed by a vessel at Essington-1 in August 2025 and at Charlemont-1 between August and November 2025.

Woodside Energy and ExxonMobil, via Esso Australia Resources, have taken the Final Investment Decision to develop the Turrum Phase 3 project in the Bass Strait. The new offshore gas drilling project targets underdeveloped gas resources via five new wells in the Turrum and North Turrum gas fields.

“Woodside is supporting new opportunities in one of Australia’s most important offshore oil and gas regions, developing much-needed new gas supplies to Eastern Australia,” the Australian company said in May.

Following six years of extensive federal and state reviews and delays due to challenges in court, Australia’s federal government approved in May a proposal that would see the operating life of its biggest and oldest LNG plant extended to 2070.

The Australian Government has been considering a proposal to continue the use and extend the operating life of the North West Shelf gas processing plant in Karratha, Western Australia, beyond the expiry of its current approval in 2030.

Murray Watt, Australia’s federal Minister for the Environment and Water, made a proposed decision to approve the North West Shelf extension, subject to strict conditions, particularly relating to the impact of air emissions levels from the operation of an expanded on-shore Karratha gas plant.

The project’s operator, Woodside, first proposed the extension of the operating life of the North West Shelf Project in 2018. State and federal governments have been reviewing the plans to extend life beyond 2030, as it was originally planned, amid hundreds of appeals by activists campaigning to preserve the environment and the cultural heritage of the local people.

Woodside received the Western Australia state government approval in December 2024 after six years of assessment and appeals.

Extending the environmental consent for the project, which began producing gas in 1984, means that Woodside and its partners in the project could continue to deliver gas using existing infrastructure.

“This proposed approval will secure the ongoing operation of the North West Shelf and the thousands of direct and indirect jobs that it supports,” Liz Westcott, Woodside Executive Vice President and Chief Operating Officer, Australia, said in May.

In June, Woodside and the North West Shelf Joint Venture said they continue constructive consultation with the Federal Government

on the proposed extension approval. The parties have agreed to an extension of the consultation period regarding the Government’s proposed conditions as part of the North West Shelf Project Extension environmental approval process.

“Woodside recognises the importance of the matters being addressed by the proposed conditions of the environmental approval including cultural heritage management and air quality,” the company said.

Woodside Energy has also signed a nonbinding memorandum of understanding (MOU) with Hyundai Engineering and Hyundai Glovis, establishing a strategic framework to collaborate on LNG project development, engineering services, and shipping logistics. The MOU will see the parties focus on advancing execution capability and extending their reach into priority LNG markets.

Woodside Executive Vice President and Chief Commercial Officer Mark Abbotsford said “We are confident the synergies and complementary strengths of our organisations will support the delivery of high quality LNG solutions to meet growing global demand.”

By Tsvetana Paraskova

Destec Engineering Ltd.: Pioneering High-Pressure Containment and On-Site Machining Solutions

Delivering 55 years of innovation and precision, Destec Engineering provides industry-leading portable machine tools and on-site services, reducing costs and enhancing efficiency for the oil, gas, petrochemical, and power generation sectors.

For 55 years, Destec Engineering Ltd. has delivered high quality and innovative engineering solutions to industry challenges. Specialising in ‘High Pressure Containment’ and ‘On-Site Machining’, the company has developed both products and services for the oil and gas and power industry. Formed in 1969, Destec now takes pride in its most versatile and a very wide range of in-house designed and manufactured portable machine tools.

With their distributors spread across the world in six continents, Destec has become indispensable to the oil and gas industry. The company is committed to the design and manufacture of portable machine tools, where accuracy is of paramount importance. Destec has a fully equipped machine workshop with a wide selection of CNC lathes, vertical boring and milling machines. Powered by an experienced design staff who are actively engaged in the design and development of their products, Destec provides supporting calculations and stress analysis for their products and use in-house developed computer programmes. Serving clientele all across the oil, chemical and petrochemical related industries, power generation, steel, marine and others, Destec’s well-equipped team backed by the most modern design and manufacturing equipment works closely with the clients to reduce costs. Destec Engineering has designed, developed and built special purpose machines for the oil, petrochemical and nuclear industries. Their multi-disciplined trained technicians combined with the years of expertise provide the best

on-site services which not only significantly reduces the personnel on the field but also is less harsh on the client’s pockets.

Known for their quality assurance, their clients are drawn to the versatility and adaptability of their products coupled with accuracy. Destec serves the client’s needs best through their cost-efficient solutions and their perfect surface finished products ensure that they hold well in-situ. Over the years, they have generated a sense of trust in their clients with their qualityassured products and onsite services.

Destec stands tall as a one-stop solution for all the machinery requirements. This implies cutting down significantly on the costs of stripping down, transporting to a machine shop, returning to site, and reassembly. That is why their clients rely on trustworthy services of taking a special-purpose machine to the job instead.

Destec’s products are the most-trusted by the oil and gas industry with their years of experience on the use of high-pressure and high-temperature metal-to-metal static sealing. Their engineers are driven by quality assurance and follow established codes and standards for design modifications. Destec’s on-site machining service uses portable machines to carry out those modifications and re-build on site.

With their years of experience on the field and a passion-driven team of engineers, Destec has created a niche for its products and services which are unparalleled in the industry. 

“Our strength lies in our ability to listen to operators, adapt quickly, and deliver precisionengineered inflatable and expandable technologies that perform where it matters mostdownhole.”

Clem Rowe, Founder & CEO

Advanced Packers for the Worldʼs Toughest Challenges

Established in 1999, IPI Packers is a leading designer and manufacturer of high-performance inflatable and expandable downhole products, supporting the global oil and gas sector with specialised solutions tailored to complex well challenges.

Our origins lie in Perth, Western Australia, where IPIʼs engineering excellence and primary manufacturing centre is located. The global commercial centre is in the UAE, and further regional hubs are in Europe and North America, giving IPI a combination of local responsiveness with global capability. This footprint allows us to work closely with clients across the world, placing our experts geographically close to our customers, delivering solutions that align with specific operational, regulatory, and environmental needs.

IPIʼs approach has always been grounded in engineering excellence and technical collaboration. We work directly with operators and service companies to truly understand the problems our customers are facing up to.

IPIʼs technology supports all stages of the well lifecycle, from drilling and completions

to wellbore intervention, production optimisation, and all the way to plug and abandonment. Whether addressing annular isolation, high-pressure / high temperature, or complex open-hole scenarios, IPI tools are designed for durability, reliability, and operational efficiency.

Our unique inflatable packer element technology incorporates elastomers, reinforcement layers, and external anchoring surface finishes (DuraGRIP™) within a single, vulcanised composite unit. This innovative contrawound design replaces more typical inflatable packer components such as non-reinforced inflation bladders, exposed reinforcement layers, and separate rubber covers. IPIʼs true composite design eliminates issues commonly associated with alternatives available in the market while increasing

- Custom manufacturing expands

- Sales agents appointed in Americas & Europe

2002-2005

1999 – 2001

- IPI Packers founded in Perth, Australia

- First workshop established

Custom Packer Experts

In addition to our core product lines, IPI Packers is a trusted OEM partner to several leading service companies across the oil and gas sector, designing and manufacturing highperformance packer elements and expandable sleeves tailored to specific field requirements.

These long-standing partnerships are built on a foundation of technical expertise, trust, and a shared commitment to delivering downhole solutions that meet the demands of increasingly complex well environments.

Our in-house R&D and design teams are at the forefront of innovation, often collaborating directly with clients to develop new technologies in response to realworld challenges. Whether itʼs adapting an existing tool for a specialised application or engineering a completely new concept from first principles, IPI is known for its ability to respond quickly and deliver with precision.

Our Journey & Milestones

This flexibility and problem-solving mindset are what continues to set us apart as a technical partner in downhole tool development and push the limits of what is possible in the inflatable and expandable space. 

- QMS achieved ISO 9001 compliance

- New USA warehouse & service center opened

2011-2015

- Purpose-built workshop & rubber lab built in Perth - Element workshop set up in Bulgaria

2019-2021

Perth acquires ISO 14001 certification

2023

2006-2010

- Three CNC lathes & Mk2 machines commissioned

- Two workshops installed

- Offices in Singapore, USA & Latin America

2016-2018

- Won Western Australia​ “Innovator of the Year”

- Perth facility ISO 9001 and 45001 accredited

2022

- UAE Commercial Centre established

- Element production expands in Europe

2024

- Crossed 100+ employees

- Europe facility ISO 9001, 14001, 45001 certified

What makes an EEHA Dossier?

Classification Report

Manufacturers Documentation

Equipment Schedules

Certificates of Compliance

Intrinsically Safe Calculations

Maintenance Management Plan

HA Classification Drawings

P & ID Drawings

Electrical Drawings

Documentary Records

Initial Detail Inspection ITRs

Historical Inspection ITRs

Cable Schedules

In the toughest industries, safety and skill aren’t optional, they’re everything.

Flexible courses tailored to your site and schedule

Industry-experienced trainers who’ve worked where you work

Global reach - training across Australia and worldwide

Proven results in reducing risk and improving workforce capability

MOXI & Haztech: Raising the Bar for EEHA Compliance in Mining

In the mining industry, potential dangers are as ubiquitous as the rocks that are excavated. Ensuring that all electrical equipment adheres to stringent safety standards and regulations is a monumental task. It is here that MOXI enters the fray with its Electrical Equipment in Hazardous Areas (EEHA) audit checklist and inspection procedure.

Crafted to assist mining companies in successfully navigating the complex terrain of safety compliance, the focus is firmly on protecting the wellbeing of workers and ensuring smooth operational continuity.

EEHA audit checklist

These EEHA audits transcend the mere formality of ticking boxes for mining companies.

The comprehensive checklist developed by MOXI addresses every conceivable aspect, from the minute details of documentation to the physical condition of equipment, best practices for installation and emergency procedures. It serves as a tool that aids mining companies in maintaining strict compliance with safety regulations, while simultaneously minimising the risk of accidents.

The EEHA audit checklist commences with certifications, inspection records and risk assessments. MOXI is relentless in emphasising the necessity of impeccable record keeping. This includes the mandate that all electrical equipment is certified for use in hazardous zones in Australia & New Zealand, such as those meeting ATEX, UL and IECEx standards.

Next, MOXI advises an examination of equipment labels to ensure their accuracy, displaying their hazardous area classification and certification details. Identification tags must be clearly visible and easy to read. Ensuring the correct area classification and its accurate documentation is also a nonnegotiable requirement.

Another component of the audit process is the examination of the physical condition of electrical equipment. There should be no indications of damage or corrosion. Enclosures must be intact and graded for the hazardous area they inhabit, while cable entries and conduits should be appropriately sealed to prevent dust or moisture ingress.

Touching upon installation practices, MOXI’s recommendation is to meticulously verify that wiring and connections are in perfect condition and well-insulated. Grounding and bonding must be executed correctly and kept current.

Routine maintenance should be conducted in accordance with the manufacturer’s instructions and industry standards, incorporating regular equipment testing such

as insulation resistance testing. Emergency procedures must be established and familiar to relevant personnel, with appropriate safety training imparted to those operating in hazardous zones.

The checklist concludes with a review of compliance with pertinent standards, such as IEC 60079 and AS/NZS 60079, adherence to local regulations, and industry best practices. It also mandates maintaining previous audit reports on hand and ensuring any corrections from these reports have been implemented.

EEHA inspection procedure

MOXI’s EEHA inspection procedure offers a comprehensive guide to executing EEHA inspections. It spans from the preparatory stage, which encompasses familiarising with the relevant standards and collating necessary documentation, right through to the inspection process itself. This includes visual checks for signs of damage, testing equipment under normal operating conditions, verifying compliance with area classification standards, and assessing for environmental impact.

Record-keeping forms a vital component of the procedure, complemented by the preparation of a detailed inspection report for review and approval by the concerned authorities. Followup actions encompass executing any necessary repairs identified during the inspection and scheduling re-inspections to ascertain the effectiveness of the corrective measures.

MOXI’s EEHA tools are designed to assist mining companies in deciphering safety compliance in hazardous areas. MOXI delineates a clear path to adhere to requisite safety standards and regulations, thereby providing a shield for both workers and operations from the inherent potential risks.

The audit checklist and inspection procedure act as a roadmap to compliance, safety and operational excellence for mining companies operating in hazardous zones. Although it offers a comprehensive approach, MOXI additionally suggests engaging with specialists or manufacturers for guidance on complex issues or unfamiliar equipment.

Ultimately, MOXI’s EEHA offerings provide a valuable resource for any mining company eager to safeguard its operations from the

inherent risks associated with working in hazardous environments. With an emphasis on detailed, thorough procedures and safety, MOXI represent a crucial addition to the industry’s best practices toolkit.

MOXI partners with Haztech for the provision of EEHA Inspection services……

To further enhance its EEHA service offering, MOXI has partnered with Haztech Solutions, a specialist Electrical & Instrumentation company with extensive experience in hazardous area compliance and inspection services. This collaboration brings together MOXI’s proven tools and methodologies with Haztech’s boots-on-the-ground expertise to deliver a turnkey solution for mining operators across Australia.

Haztech Solutions plays a critical role in bringing the EEHA audit checklist and inspection procedures to life in the field. With a team of qualified hazardous area electricians and inspectors, Haztech ensures that compliance requirements outlined in the MOXI framework are not only met, but exceeded. Their hands-on approach to inspections, installations, and remediation ensures seamless execution — from identifying non-conformances through to certifying corrective actions in line with IECEx and AS/NZS 60079 standards.

What sets Haztech apart is its operational readiness and agility. Whether supporting brownfield maintenance programs or greenfield commissioning scopes, Haztech operates with a deep understanding of the unique challenges presented by mining environments. Their focus on traceability, digital inspection reports, and asset lifecycle management complements MOXI’s structured approach, giving mining clients full transparency and peace of mind when it comes to compliance and safety.

Together, MOXI and Haztech Solutions offer a unified EEHA solution that blends technical assurance with real-world execution — reducing risk, enhancing safety, and streamlining compliance for hazardous area operations in the mining sector. 

Australia’s Subsea Surge: A New Era for Wells and Offshore Innovation

Australia is rapidly emerging as a focal point for global subsea investment, with a suite of major offshore projects driving a new wave of innovation and opportunity across the region.

As Andrew Harwood, Asia Pacific Research Director at Wood Mackenzie, recently noted:

“Australia will be the largest destination for subsea investment, as drilling and offshore construction activity at the Ichthys, Crux, Scarborough and Barossa projects pick up.”

This momentum reflects a broader shift in the energy landscape - one where advanced subsea technologies, smarter well strategies, and integrated digital solutions are reshaping how offshore operations are planned, executed, and optimised.

Strategic Projects Leading the Charge

The Scarborough and Barossa developments, alongside the expansion of Ichthys and Crux, are not just large-scale investments, they’re strategic platforms for deploying next-generation subsea systems. These projects are leveraging cutting-edge robotics, modular well architectures, and real-time data analytics to improve safety, reduce costs, and enhance production efficiency.

Australia’s unique offshore conditionsdeepwater environments, remote operations, and complex reservoirs - make it ideal grounds for innovation. Operators are increasingly adopting autonomous inspection tools, digital twins, and AI-driven maintenance planning to extend asset life and reduce downtime.

Wells and Subsea: A Converging Frontier

The convergence of well engineering and subsea technology is creating new possibilities for field development. Smart wells, integrated with subsea control systems, are enabling more precise reservoir management and adaptive production strategies. This is particularly valuable in Australia’s frontier basins, where agility and insight are critical to unlocking long-term value.

Digitalisation is also playing a key role. From automated well integrity monitoring to predictive analytics for subsea equipment, data is becoming the backbone of smarter decision-making. The result is a more connected, responsive, and resilient offshore ecosystem.

THREE60 Energy: Enabling the Next Wave

As this transformation accelerates, THREE60 Energy is uniquely positioned to support operators across Australia’s offshore landscape. Through its digital division, THREE60 delivers  knowledge as a service - a powerful approach that turns fragmented data into actionable insight, tailored to the specific needs of wells and subsea operations.

By combining deep domain expertise with agile digital development, THREE60 helps clients automate engineering workflows, optimise asset performance, and accelerate project delivery.

Their modular, cloud-based architecture enables faster deployment, better collaboration, and scalable solutions that evolve with the business.

Whether it’s supporting well planning, enhancing subsea inspection, or integrating real-time data into decision-making, THREE60 Energy is helping operators unlock the full value of their offshore assets - safely, efficiently, and sustainably.

Building a Sustainable Future

Beyond operational gains, Australia’s subsea investments are contributing to broader sustainability goals. By improving efficiency and reducing emissions through smarter design and automation, these projects support the industry’s transition to lowercarbon operations.

Moreover, the skills and technologies developed here are setting benchmarks for global best practice. Australia is not just investing in infrastructure - it’s investing in capability, collaboration, and long-term competitiveness.

What’s Next?

As activity ramps up across key offshore hubs, the focus will increasingly shift to integration - bringing together wells, subsea systems, and digital platforms into unified, agile solutions. Companies that embrace this convergence will be best positioned to lead in performance, innovation, and sustainability.

Australia’s subsea surge is more than a trend - it’s a transformation. And with partners like THREE60 Energy, the future of offshore operations is not only smarter, it’s already here.

Better Energy Together

The APAC CCUS opportunity–distance, diversity and demand

Asia-Pacific (APAC) is home to more than half of global CO2 emissions, making the deployment of CCUS in countries like Japan, South Korea and Australia a key underpinning technology for decarbonisation.

Earlier this year, Xodus, in partnership with Subsea7, painted the most detailed picture yet of how APAC’s CCUS infrastructure is likely to evolve between now and 2055.

The Forecasting the APAC CCUS Infrastructure report tells a story of significant opportunity, for the APAC region to provide emitters with cost efficient storage options and lead the world in cross border emissions transportation.

One of the key conclusions it draws is that CCUS projects linked to LNG infrastructure offer a flexible, proven and cost-efficient path, meaning they can reduce tariff costs by up to 15% – the equivalent of shortening shipping distances by 3,000 km.

Distance defines the market

The APAC story is defined by geography. Japan and South Korea, two of the region’s largest emitters with decarbonisation ambitions, sit more than 5,000 kilometres from currently viable storage basins in Southeast Asia and Northern Australia. For comparison, Europe’s longest CO₂ shipping route is less than a quarter of that distance.

This mismatch means APAC will rely heavily on long-distance shipping in the early years, however proving the viability of saline aquifers for CO2 storage will dramatically shift market dynamics. International cooperation and regulatory alignment will be essential to unlock projects and establish a functioning cross-border CO₂ market.

The first wave expected in the next decade

By 2035, of 30 CCUS projects currently announced across APAC, Xodus expects at least four commercial-scale developments to be operational.

South Korea and Japan are projected to lead the pack in capturing emissions at around 17 million tonnes per annum (MTPA) of CO₂, split between domestic and international storage.

In addition, the need to remove significant quantities of CO₂ from natural gas is a common factor across LNG projects in APAC.

Key storage markets at this stage are in North Asia, Australia, Indonesia and Malaysia. For example, Malaysia’s Petronas is developing hub clusters in the Penyu Basin that rely on saline aquifers, requiring long-term cooperation between host and importing nations.

At the same time, domestic projects are taking shape in Northeast Asia, including Japan’s Metropolitan Area CCS Project and South Korea’s Donghae Project, are expensive but crucial stepping stones in establishing a regional CCUS value chain.

Importing CO₂ provides an opportunity for LNG projects to share the cost of CCUS infrastructure while providing a service to remote emitters. This shared-use model can offer tremendous cost savings in the early stage of CCUS roll-out across APAC.

By the early 2040s, APAC’s CCUS market could expand fifteen-fold in captured emissions, requiring more than 50 offshore storage sites, 4,000 kilometres of pipelines and nearly 70 CO₂ transport vessels.

A key driver will be the development of domestic storage in Japan and South Korea, coupled with new entrants in Southeast Asia that will allow CCUS to scale quickly and cost-effectively.

Infrastructure reuse in Malaysia and Indonesia

By 2045, many projects - including Malaysia’s Kasawari and Timor Leste’s Bayu Undancould reuse existing infrastructure, such as pipelines, to lower the commercial barrier to the development of CCUS projects.

Up to 30% of pipeline needs could be met through re-use, reducing both costs and the carbon footprint of new CCUS infrastructure.

By Simon Allison, Vice President, APAC, Xodus

The state of play come 2055

By 2055, Xodus foresees more than 90 storage sites, close to 8,000 km of pipelines and over 75 shipping vessels in service, collectively storing around 540 MTPA of CO₂.

In Japan and South Korea alone, the storage demand could require an offshore industry similar in scale to gas infrastructure offshore Northwest Australia. By this point APAC’s CCUS industry is expected to operate in three distinct markets:

• Northeast Asia stores 80% of its projected 260 MTPA domestically

• Southeast Asia stores 240 MTPA across Vietnam, Malaysia and Indonesia

• Australia and New Zealand store 90 MTPA, including both domestic and imported emissions

Cross-border shipping capacity will also grow, though its market share is forecast to fall below 12%. Still, over 75 vessels – about 20% of Asia’s current LNG fleet – will be needed. Vietnam and Indonesia are expected to gain market share from shipping volume as they develop storage closer to emitters.

Cost savings for CCUS exporters

A shared-use model offers major tariff reductions for imported industrial CO₂ volumes by leveraging shared infrastructure, low marginal costs and economies of scale.

These savings are equivalent to shortening shipping distances by over 3,000 km, effectively shortening the distance between CCUS projects like Australia’s Bonaparte and countries like Japan.

While early offshore transport and storage costs are high due to long distances, they will fall as local stores are developed. APAC’s high density of industrial emissions also keeps capture and onshore collection costs low – making CCUS highly competitive in the long run. 

Woodside Strengthens Its Australian Operations

Woodside has agreed to assume operatorship of the Bass Strait assets, unlocking potential development of additional gas resources, following an historic agreement with ExxonMobil Australia (ExxonMobil). Consolidating operatorship of the Bass Strait assets into Woodside’s operated portfolio strengthens Woodside’s footprint in Australia and reflects Woodside’s long history of operating excellence.

From completion, Woodside will assume operatorship of the offshore Bass Strait production assets, the Longford Gas Plant, the Long Island Point gas liquids processing facility and associated pipeline infrastructure. Woodside and ExxonMobil’s equity interests in the assets and current decommissioning plans and provisions remain unchanged.

As operator, Woodside will take on the responsibility for asset planning and execution activities, pursuing a value maximisation strategy that targets further production and reliability improvements. This strategic move combines Woodside’s existing global operating capabilities with ExxonMobil’s highly experienced Bass Strait workforce who will transfer to Woodside, further strengthening Woodside’s overall operating expertise.

Operatorship of a larger group of assets in Australia will create economies of scale which are expected to realise over US$60

million in synergies for Woodside from the Bass Strait after deduction of transition and integration costs.

The agreement also creates flexibility to realise future development opportunities that meet Woodside’s capital allocation framework. Woodside has identified four potential development wells that could deliver up to 200 petajoules of sales gas to the market. Under the agreement, Woodside can solely develop these opportunities through the Bass Strait infrastructure subject to further technical maturation and a final investment decision. This potential production has been identified from within the existing contingent resource opportunity set.1

Woodside EVP and COO Australia Liz Westcott said the rationale for the agreement is compelling and the transfer of operatorship reinforces Woodside’s position as Australia’s leading energy company.

“As a proudly Australian company, Woodside supports essential domestic energy needs in both Western Australia through the North West Shelf, Pluto and Macedon operations, and on the east coast through its equity participation in Bass Strait.

“Taking operatorship of Bass Strait demonstrates Woodside’s continued commitment to meeting Australia’s domestic energy demand while maximising the value of existing infrastructure,” she said.

ExxonMobil Australia Chair Simon Younger said ExxonMobil remains committed to providing reliable supplies of gas to its customers in Australia.

“After operating the Gippsland Basin Joint Venture for more than 50 years, we are proud to be handing over the reins and transitioning our highly experienced Bass Strait workforce to our valued partner Woodside, a worldclass operator. We look forward to working with Woodside as it continues to maximise Gippsland Basin production,” he said. 

INPEX Masela Awards Major FEED Contracts for Abadi LNG Project

Progress is being made on the Abadi LNG project in Indonesia, as INPEX Masela, a subsidiary of INPEX, has announced the awarding of major contracts for the front-end engineering and design (FEED) phase.

The project, which incorporates a carbon capture and storage (CCS) component, is moving forward following the Indonesian government’s approval of a revised development plan in December 2023.

Contracts were awarded for three of the four primary FEED packages. For the floating production, storage and offloading (FPSO) unit, Saipem Indonesia and Technip Engineering Indonesia will each lead a consortium in a “dual-FEED” process to enhance competition. Worley SEA Indonesia has been selected to handle the subsea umbilicals, risers, and flowlines (SURF) and gas export pipeline (GEP) packages. The final contract for the onshore LNG plant (OLNG) has not yet been awarded. 

Mount Burgess snaps up two gold projects

Mount Burgess Mining is set to acquire two advanced gold projects in Western Australia from Falcon Metals and Metal Hawk, increasing its exposure to the gold sector.

The first project to be acquired by Mount Burgess is the Viking gold project, located 30km east of Norseman.

Considered an “exciting high-grade gold opportunity”, drillhole intersections recorded in 2022 by Falcon Metals from the Beaker 2 prospect include 6m at 64 grams per tonne (g/t) of gold from 50m.

Mount Burgess believes previous exploration highlights potential for “a significant mineralised system”. The company plans to carry out additional drilling to gain a better understanding of the gold mineralisation, the majority of which remains open along strike and at depth.

The second project to be acquired by Mount Burgess is the Blair North gold project, located 25km east of Kalgoorlie.

Blair North has been previously explored by Metal Hawk, where nickel sulphide and primary gold mineralisation was identified at the Commodore and Commodore North prospects.

Drillhole intersections from the Commodore prospect include 1m at 5.9 per cent nickel from 144m and 5.9m at 6.7g/t of gold from 244m, and drillhole intersections from the Commodore North prospect include 8m at

0.96g/t of gold from 74m and 4m at 1.69g/t of gold from 96m.

Mount Burgess is expected to carry out further drilling targeting additional zones of high-grade gold mineralisation along the Commodore trend.

“We are delighted to have secured these two exciting West Australian gold projects,” Mount Burgess executive chairman Steve Lennon said.

“We believe this a great result for (Mount Burgess) shareholders as we look forward to realising the potential of these highly prospective and underexplored tenement packages.

“Commencing gold exploration on these projects will be the company’s immediate focus as we endeavour to get on the ground and start work as soon as possible.”

The company has commenced applications for programme of works approvals, with the aim to commence drilling at Viking and Blair North in the fourth quarter of 2025.

Once the acquisition and a parallel $900,000 placement have been finalised, Metal Hawk will own 17.5 per cent of Mount Burgess, and Falcon Metals will hold a 7.8 per cent stake.. 

JBS secures first Sea Axe contract in South Korea

JBS has secured its first Sea Axe contract in South Korea, supporting the Yeonggwang Nakwol Offshore Wind Farm project.

Working with Haechun, the Sea Axe spread –equipped with an electric HPU – will carry out underwater cable burial operations to a depth of two metres.

The scope includes 44km of 234mm export cable and approximately 164km of inter-array cable for the 364.8MW development.

Jo McIntosh, Sales & Marketing Director at Jbs, said: “This is fantastic news for Jbs and we are looking forward to working with the talented team at Haechun. This milestone project strengthens our operations in Asia, where we also deliver and install blast containment solutions and screw conveyors.”

Jbs has delivered projects in 80 countries and works across numerous sectors including energy, marine and space.

Known for its innovative Sea Axe technology, Jbs provides efficient, environmentally friendly subsea excavation solutions, reducing deck space requirements and enhancing safety.

The company also offers custom fabrication projects for the energy sector, including deployment frames, and supplies patented blast containment products for fire and arc flash protection.

The firm’s screw conveyors, including dual drive options, serve clients worldwide, supporting operations in energy and industrial sectors.

Jbs won the Going Global honour at the 2023 Northern Star Business Awards, organised by Aberdeen & Grampian Chamber of Commerce. 

Saipem secures

Scarabeo 8 contract extension with Aker BP until 2027

Aker BP has exercised the option to extend a contract with Saipem for the semi-submersible drilling unit Scarabeo 8 until 31 December 2027.

The extension is a direct continuation of the previous one-year contract and solidifies the ongoing collaboration between the two companies.

The contract was originally awarded by Aker BP to Saipem for a drilling campaign for a three-year period in March 2022. The $325m (€284.88m) contract included the option of two one-year extensions.

The Scarabeo 8, a sixth-generation drilling unit owned by Saipem, will continue to perform drilling activities for Aker BP offshore Norway.

Designed to withstand challenging offshore conditions, the derrick deep-water unit is equipped with dynamic positioning and advanced mooring systems, adhering to the highest regulatory standards.

Saipem’s Scarabeo 8 drilling rig was previously employed on various projects with major oil companies across the Norwegian Continental Shelf (NCS), including the Barents Sea.

In a press release, Saipem said this contract extension is a testament to the unit’s high performance and Saipem’s commitment to safety and efficiency.

In July 2024, Aker BP and its partners announced a gas discovery in an exploration well, drilled with the Scarabeo 8 rig in the Barents Sea, nearly 300km off Norway’s northern coastline.

Designated 7324/8-4 (Hassel), the discovery followed the initial exploration effort at well 7324/6-2 in production licence 1170.

Saipem provides engineering services for the design, construction and operation of complex energy infrastructure and plants, both offshore and onshore.

With an employee base of 30,000, the company operates in 50 countries through six business lines: Asset Based Services, Drilling, Energy Carriers, Offshore Wind, Robotics & Industrialized Solutions, and Sustainable Infrastructures. 

Governments set to refund Chevron $500m for Barrow Island oil field clean-up

The $2.3 billion-plus decommissioning on a WA nature reserve will be part-funded by the Federal and WA governments returning about half the royalties they received over six decades.

In May, Chevron stopped producing oil on Barrow Island off the WA coast, and the clock on a 40-year-old agreement started ticking which will likely require the Federal and WA governments to pay more than $500 million towards the clean-up bill.

After drilling about 900 wells over six decades, it will cost Chevron more than $2.3 billion to clean up the offshore nature reserve, according to a WA government minute obtained by a Boiling Cold freedom of information request.

During that time, Chevron produced 335 million barrels of oil and paid more than $1 billion in royalties, or about $3 per barrel.

In the coming years, about half of those royalties will flow back to Chevron and its partners to offset their clean-up costs, diminishing the total value Australia got from the extraction of its resources.

The calculation that will cost Australian taxpayers

Since 1985, royalties paid for extracting oil from under Barrow Island have been calculated under a WA Act written especially for the project.

The royalty – 40 per cent of the difference between Chevron’s sales revenue and operational costs – has been paid 75 per cent to the Federal Government and 25 per cent to WA.

However, under the Act, from May 2025, when production ended, and for the following three years, the calculation operates in reverse.

Chevron and its partners will be refunded 40 per cent of what they spend on decommissioning the oil field infrastructure before 31 December 2028, with the two governments paying in the same ratio they received royalties. The total refund is capped at the value of all royalties received.

In the absence of any information from Chevron, in 2022, the WA mining regulator used a media report that $1.29 billion of a total bill $2.3 billion would be spent in the royalty refund period to calculate that the state would refund about $129 million in royalties.

This implies the Federal Government would pay $387 million, with Chevron and its partners receiving a total of $516 million.

However, the refund could be higher, as the cost is now estimated to be more than $2.3 billion. Additionally, there is a considerable incentive for Chevron to do as much work as possible before 2029 to maximise the refund.

In May, the same month production ended, Chevron informed its regulator, the Department of Mining, Petroleum and Exploration (DMPE), that an unknown amount of gas was seeping to the surface near its old oil wells. The seeps add to widespread contamination of Barrow Island by Chevron.

A Chevron spokesman said while some costs would be refunded, it and its partners, Santos and ExxonMobil, would bear the vast majority of the total cost.

“We will continue to engage with state and federal governments in relation to the WA Oil decommissioning project and the administration of the royalty regime,” he said.

Neither government seems to know what it might have to pay to Chevron.

A DMPE spokesman said the cost was not included in its forward estimates, but the potential liability was “recognised as a nonquantifiable contingent liability” in the Annual Report on State Finances.

The report acknowledged that “a significant amount of royalties will need to be refunded,” but only after Chevron pays the costs and the state verifies and audits them.

It is understood that the Federal Government is waiting on WA to determine the total refund, as the state administers the royalty regime.

A complex job in an extraordinary nature reserve

The scope of the clean-up is enormous and complicated.

About 700 of the almost wells 900 are more than 40 years old, according to the WA Government’s database of wells.

At the start of 2025, 316 wells were still producing about 3600 barrels of oil a day, according to an environment plan lodged by Chevron.

Up to four drilling rigs will plug and abandon the wells—a procedure that permanently seals the oil and gas underground, typically using cement. Two rigs may operate 24 hours a day.

Then, the wellheads are removed, as well as almost all other equipment and their concrete foundations. Sixteen areas contaminated with hydrocarbons require attention.

All this must be done on a hot, exposed island 70km of the north-west coast of WA while not causing further contamination, managing fire risk and protecting the vast array of native species that flourish on the island due to a lack of introduced weeds and predators so common on the mainland.

Afterwards, the giant Gorgon gas export plant, also operated by Chevron, will remain on the island.

Barrow bill is a fraction of the work ahead

The shuttered oil asset on Barrow Island is owned by Chevron (57 per cent), Santos (29 per cent), and ExxonMobil (14 per cent).

If cleaning up Barrow Island does cost $2.3 billion, Santos will have to contribute $667 million.

The work has begun as the Abu Dhabi National Oil Company conducts due diligence on Santos in preparation for a potential takeover.

Whether the $6 billion decommissioning liability Santos reports on its balance sheet is adequate to cover the work it must do across its operations is reportedly a focus of due diligence underway to support the $36 billion takeover. 

Kent wins Australian offshore decommissioning gig

Host government responsible for decommissioning the Laminaria-Corallina oilfields after liquidation of former operator NOGA

Integrated energy services company Kent has won a new technical advisory services contract from the Australian government to support the permanent plugging and abandonment of the Laminaria-Corallina oilfields in the Timor Sea.

The contract also includes advisory services for the safe removal of associated subsea infrastructure.

Under the initial two-year contract, Nesma & Partners-backed Kent will deploy a multidisciplinary team of technical and regulatory experts to provide strategic and operational support throughout the planning and execution of the decommissioning.

The value of the contract was not disclosed.

“Our advisory team, with deep roots in Australia and the UK, is energised by this opportunity to help shape the future of offshore decommissioning,” commented Michael Costello, executive vice president — development, APAC & Americas at Kent.

Building on existing work on the Northern Endeavour floating production, storage and offloading vessel, the contractor said the latest award underscores its position as a trusted decommissioning partner with a deep commitment to regulatory compliance, environmental stewardship and technical excellence.

The Northern Endeavour FPSO is permanently moored between the Laminaria and Corallina fields in the Timor Sea. Following the liquidation of its former operator, Northern Oil & Gas Australia (NOGA), the facility was transferred to the ownership of the Commonwealth of Australia.

The safe decommissioning of the FPSO and associated infrastructure is a key priority under the government’s broader strategy for responsible offshore oil and gas transition, noted Kent. This includes full lifecycle management of offshore assets and a commitment to protecting Australia’s marine environment through safe, sustainable decommissioning practices. 

Australia’s Decommissioning Market Accelerates with New Contracts and Regulatory Scrutiny

Australia’s offshore decommissioning market is gaining momentum, marked by significant new contract awards and heightened regulatory oversight.

The past two weeks have seen key developments that underscore the nation’s commitment to responsibly retiring aging offshore assets, while also highlighting the complexities and challenges of this growing industry.

In a major development, the integrated energy services company Kent was awarded a new technical advisory contract by the Australian government. The two-year contract is for advisory services to support the permanent plugging and abandonment of the Laminaria-Corallina oil fields in the Timor Sea and the safe removal of associated subsea infrastructure. This work is a crucial part of the government’s decommissioning

program for the Northern Endeavour floating production, storage, and offloading (FPSO) facility, which it assumed responsibility for following the liquidation of the former operator.

Meanwhile, regulatory scrutiny is intensifying. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) has issued new general directions to Woodside Energy concerning its ongoing decommissioning and removal activities at the Stybarrow, Griffin, and Minerva fields. NOPSEMA’s directions were prompted by unexpected site conditions and a series of safety incidents. 

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Transforming

As the offshore energy sector accelerates its digital transformation, technology is playing an increasingly central role in improving operational efficiency. This is particularly evident in crew travel and logistics, where managing complexity, cost, and compliance remains a constant challenge. ATPI is addressing these issues through two proprietary platforms, CrewHub and CrewLink, developed specifically for the needs of the offshore and energy industries.

CrewHub: Simplifying the Booking Process

ATPI CrewHub is a booking platform designed to reduce the complexity of group travel in the offshore sector. Tailored to the energy industry’s unique requirements, it enables users to arrange multi-origin, multi-destination itineraries through a straightforward interface with just five required input fields.

By streamlining the booking process, CrewHub helps reduce reliance on email threads, spreadsheets, and disconnected systems. Users report booking time reductions of up to 60%, allowing teams to focus on highervalue tasks. Whether organising a deployment involving multiple countries or managing recurring crew rotations, CrewHub brings all logistics into one place.

The platform offers flexible filtering, by speed, price, or operational preferences, supporting offshore-specific considerations such as remote destinations and last-minute changes. With options to manage up to 20 route combinations per booking, CrewHub accommodates complex mobilisations while helping operators monitor and manage travel spend effectively.

CrewHub also supports direct control by users, allowing them to create, amend, or cancel bookings instantly without third-party intervention. This autonomy can improve responsiveness, particularly in time-sensitive or changing operational contexts.

CrewLink: Centralising Crew Management for Total Control

While CrewHub simplifies the booking process, CrewLink addresses the broader operational challenges involved in managing the entire lifecycle of crew logistics. Designed to handle the ongoing operational demands of maritime and offshore environments, it brings together scheduling, compliance tracking, communication tools, and wellbeing oversight into a single, integrated platform.

In offshore environments where work often takes place in remote or high-risk locations, duty of care extends beyond regulatory compliance. It involves ensuring that workers are supported through clear communication, safe scheduling practices, and responsive planning. CrewLink incorporates these elements by offering real-time visibility into crew movements, enabling operators to respond quickly in the event of disruptions such as extreme weather, logistical delays, or medical issues.

The platform’s rostering tools support more sustainable planning by helping coordinators avoid fatigue risks, ensure rest periods, and prioritise direct travel routes when feasible. CrewLink also allows planners to consider availability, qualifications, and individual preferences, which can contribute to more consistent deployments and reduce administrative overhead.

Communication features built into the system help maintain contact with travelling personnel, facilitating timely updates and support when needed. In operational contexts where conditions may change quickly, the ability to stay connected and informed is key to maintaining safety and coordination.

By bringing these functions into a central platform, CrewLink aims to support more efficient logistics while reinforcing the importance of crew wellbeing as part of daily operations.

The Future of Offshore Travel

Together, CrewHub and CrewLink offer an integrated approach to offshore crew travel and logistics. CrewHub focuses on simplifying and accelerating the booking process, while CrewLink supports long-term planning and oversight. By addressing both the tactical and strategic aspects of crew movement, these platforms help operators improve efficiency, maintain compliance, and better support their workforce in demanding environments.

As project requirements evolve and global operations expand, these tools provide a foundation for more responsive and informed decision-making in offshore travel management.

Zara Higgins, Arjaa ATPI General Manager Saudi Arabia & Head of Energy

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As one of the largest privately owned independent well management companies, we are experts in providing all aspects of well engineering and project management to our global client base.

Owned and managed by well engineers with over 40 years of experience in the industry

Skilled and multi-disciplined team with experience in all types of well projects

Drilling, completion, well integrity, intervention & decommissioning

Delivery of 160+ projects for 65+ clients since 2012

Operations performed across all phases of the well life cycle

Projects delivered in the UK, Australia, Europe, South America & Africa

Specialists in Onshore, Offshore, Rig Less, HPHT, Deepwater, High H2S, Geothermal and CCUS

For further information: www.zenith-energy.com info@zenith-energy.com.au