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OMV has announced that its Essar well in Libya’s Sirte Basin is commercially viable, following the completion of technical and economic studies

The well is in the concession area C 103, where OMV holds a 12% interest.

Zueitina Oil Company will be responsible for developing the field, where studies indicate total recoverable resources of up to 43mn barrels of oil. Due to its proximity to existing production and processing facilities, the field can be developed quickly and brought on stream in a cost-efficient manner, OMV says.

OMV has a long history of exploration and production of oil and gas in North Africa, in close cooperation with local partners, and the region plays an important role in the company’s upstream growth strategy. Libya is a core focus, where the company has been active for around 50 years with a long-standing partnership with the NOC. At the end of 2024, the company resumed exploration activities in Libya after an interruption of more than ten years.

“The Essar discovery is a major milestone for OMV and our partners at the NOC. It confirms not only Libya’s considerable potential, but also the value of long-term partnerships, technical excellence, and our unwavering commitment on the ground. Strategic collaborations such as this are essential to providing the energy the world needs,” said Berislav Gašo, OMV executive vice president Energy.

Strong potential

The recent discovery is good news for Libya, and is a further indication of its energy potential. Libya holds Africa’s largest proven oil reserves and its fifth largest gas reserves. Libya’s oil production currently stands at around 1.4mn bpd, its highest level since 2013. Libya’s NOC is keen to revitalise the country’s oil and gas industry and aims to produce 1.6mn bpd by the end of 2026, rising to 2mn bpd in the medium term, seeing the participation of international companies as crucial to achieving its growth plans. Libya’s efforts to boost oil and gas production following years of civil war have met with considerable success. In recent developments, Eni, in partnership with the Libyan National Oil Corporation (NOC) through the Mellitah Oil & Gas joint venture, has started hydrocarbon production enabled by the Sabratha Compression Project, a strategic offshore development designed to boost gas output from the Bahr Essalam gas field, located around 100 km off the coast.

NOC has signed production sharing agreements recently with Spain’s Repsol, in partnership with the Turkish Petroleum Corporation (TPAO); and Eni, in partnership with QatarEnergy and MOL Group, with its partners, Repsol and Türkiye Petrolleri A. O. (TPAO). Five blocks were recently awarded in Libya’s recent bid round, its first in eighteen years, which attracted significant international interest.

Petroleum Development Oman (PDO) has signed a three-year Integrated Drilling Services Contract with Weatherford covering 274 wells across Marmul and Greater Saqr fields as part of its efforts to support planned production growth and improve operational efficiency

This will involve a phased drilling programme covering oil producer wells and water injector wells and is designed to
• improve delivery efficiency
• strengthen cost certainty and achieve a 20% cost reduction compared with conventional pricing models
• enable more predictable rig and resource planning across the fields and
• create greater value for Oman, by developing Omani talent, building national capabilities, expanding local opportunities and retaining greater value in Oman.

Dr. Aflah Said Al Hadhrami, director general of Petroleum Development Oman, said: "Our ability to efficiently and responsibly grow production is fundamental to maximising value from the Sultanate of Oman's hydrocarbon resources."

He added that the agreement marks another step toward production growth as a key pillar of Oman’s institutional transformation, and would support PDO’s commitment to enhancing in-country value by developing local capabilities, investing in Omani talent and retaining more value in the country.

Girish Saligram, chief executive officer of Weatherford, said the contract reflects the company’s commitment to operational excellence, innovation and sustainable value creation.

He added that Weatherford would support PDO’s objectives to improve production efficiency and ensure sustainable field development, while building local capabilities, developing Omani talent and expanding opportunities across the local value chain.

Long-standing collaboration

The award builds on a long-standing collaboration between PDO and Weatherford which saw a five- five-year contract exceeding US$500mn awarded to Weatherford in 2022 from PDO to deliver Integrated Drilling Services in the Marmul and Greater Saqr fields. At the time it was envisaged that Weatherford would deliver more than 700+ wells in the two fields over the years, combining a suite of technologies to deliver holistic and innovative solutions that maximise drilling efficiency. Weatherford said the project is an integral part of Weatherford Oman’s In-Country Value strategy and also in line with Oman’s Vision 2040 to deliver safe and sustainable energy for the future.

Saligram commented at the time, “Our Integrated Services offering is gaining significant traction in the market. This award builds on our long and proven history of delivering technology leadership and innovation and is a testament to the competitiveness of our portfolio.

“Our service quality, value proposition, and local content positioned Weatherford as the clear partner of choice and will enable safe drilling operations that maximise efficiency while delivering value and reducing carbon emissions.”

About the Marmul field

The Marmul field is a major mature onshore oil field located in the Dhofar governorate of southern Oman, containing heavy and viscous crude oil. Over the past 15 years, an extensive polymer flooding program has been implemented to enhance oil recovery and counter production declines.

About the Greater Saqr field

The Greater Saqr field is a major onshore energy development project located in the southern region of Oman, spanning an area of 112 sq km in the governorate of Shalim and Halaniyyat Islands. It combines production from six satellite fields and utilises water flooding to enhance recovery. The production capacity of the gathering station which came online in 2024 is 30,000 barrels of oil equivalent a day.

Oman’s oil production

Oman’s average daily oil production rose by more than 10% to nearly 1.1mn barrels per day (bpd) in the first six months of 2026, according to the National Centre for Statistics and Information (NCSI), up from 989,200 bpd a year earlier. The country’s oil and natural gas infrastructure has remained largely unaffected by the regional conflict, with the country’s principal export terminals located outside the Strait of Hormuz. This has enabled the sultanate to maintain uninterrupted energy exports while benefiting from higher production levels. Oman has pioneered enhanced oil recovery (EOR) techniques to reverse declining production, which have met with considerable success.

At the S&P Global Energy Middle East Petroleum & Gas Conference (MPGC) held in London, Musaab Al Mulla, Aramco's vice president of market analysis and sustainability, underlined the need for the recognition of the role refined products play in resilient energy systems, which has been brought into sharp focus in the current crisis

Al Mulla highlighted the need for a realistic approach to the role of oil and gas as the engine for economic growth and the impact of the crisis on products ranging from helium to materials and fertilisers, with shortages of the latter in turn impacting food supply.

A common theme of the event was the need for resilience and redundancy in the energy system to be able to weather such crises. Al Mulla highlighted Aramco’s focus on long-term strategic planning and investment for the future, as exemplified by its investment in the east-west pipeline which is now not only transporting crude but also products, building flexibility into the system, transporting crude to refineries for export and ensuring refined products get to market.

“The world has realised the need for more investment in pipeline infrastructure and domestic refining to ensure industry is working together,” he said.

He remarked that the crisis has demonstrated demand is resilient and has exposed the underinvestment in refineries, with capital flows being redirected towards the energy transition and resulting in a deficit of 3mn bpd.

“We need to build refineries and infrastructure while also reducing emissions,” he said, noting that Aramco has one of the lowest emissions intensities.

Discussing demand for refined products, he noted that demand for jet fuel continues to grow and refinery utilisation is at record rates.

“We believe demand will continue to be resilient, and low carbon products will be important as well,” he said.

He foresaw strong growth in chemicals with the market for durable materials growing in multiple sectors, noting that carbon-based materials can help reduce emissions. Replacing steel with polypropylene in cars can reduce emissions by 80%, for example. He also highlighted growth in demand for low carbon aviation fuel (lcaf), fossil-based jet fuel, which is 10% lower in emissions than conventional jet fuel, and complements sustainable aviation fuel (saf) as it addresses some of its limitations.

Highlighting the continuing long-term strategic importance of refining, he stressed that gasolene will still account for a significant proportion of transportation fuel by 2050.

With resilience, reliability and sustainability being global challenges, Al Mulla said that resilience for Aramco means building on operational excellence, long-term investment in oil and gas, new energies and low carbon, and localisation, noting Aramco’s 70% localisation target to ensure a resilient supply chain.

“Resilience is correlated with sustainability, you can’t be sustainable if you are not resilient,” he said. It involves not only having the flexibility to be able to adapt to shocks, but also having the capacity to innovate and grow supply while also reducing emissions, he added.

Commenting on the Middle East’s attractiveness as an investment destination, he said, “Clearly the region remains the hub for oil and gas petrochemicals and refining, and it has shown its infrastructure and energy system have been resilient in this historic crisis.”

He said Aramco is also looking at other regions, and urged the need for more investor-friendly policies in Europe, where there is a need for more domestic refining and chemicals so as not to be dependent on other regions.

Discussing the role of gas, Al Mulla said there will be increasing demand to fulfil the growing demand for power from data centres, highlighting the move towards regional data centres.

Othman Soliman, founder, SC DrillTech explains why temperature drop is not the only indicator that defines mud-cooling performance

In high-temperature and HPHT drilling operations, mud cooling is often discussed through one simple number: the visible temperature drop between the mud cooler inlet and outlet. That number is useful, but it is not enough to define performance.

A mud cooler does not work in isolation. It is part of a circulating drilling system where flow rate, mud properties, hole section, surface volume, residence time, solids loading, rig layout and operating practice all influence the thermal condition the system has to manage. When those factors are ignored, a temperature reading can create either false confidence or unnecessary concern.

The better question is not only, “How many degrees did the cooler remove?” The better question is, “Is the cooling system managing the thermal load required by this well, under these circulating conditions, with this drilling fluid?”

Why surface temperature can mislead

Flowline temperature is easy to observe, so it naturally becomes the value discussed first. It is visible, measurable and operationally important. In HPHT drilling, however, surface temperature is only the final expression of a much wider thermal process.

The mud temperature returning to surface is influenced by downhole exposure time, formation temperature, circulation rate, annular velocity, mud density, rheology, surface tank volume, ambient conditions and the time the fluid spends moving through the active system. A change in pump rate, surface volume or well section can shift the observed trend without any change in the cooler itself.

Temperature drop is not cooling capacity

A common mistake is to treat temperature drop as cooling capacity. The two are related, but they are not the same. Cooling duty depends on how much fluid is moving through the cooler and how much heat is removed from that moving mass of fluid.

A small temperature reduction at a high circulation rate may represent a greater heat removal duty than a larger temperature reduction at a much lower flow rate. Without flow and fluid context, the temperature drop alone is an incomplete performance indicator.

This matters in HPHT operations because the cooler may be protecting more than the drilling fluid. It can help reduce thermal stress on elastomers, instrumentation, surface handling equipment, pumps, shakers, centrifuges and downstream components. A cooler that appears weak by temperature drop alone may be working near its practical duty limit. A cooler that appears strong may simply be operating under easier conditions.

The drilling fluid is part of the cooling equation

Mud weight, base fluid, solids content, oil/water ratio, salinity, rheology and contamination all influence how the circulating system responds thermally. A clean, well-conditioned fluid will not behave the same way as a fluid carrying excessive low-gravity solids, poor flow properties, unstable emulsion characteristics or barite sag risk.

Thermal management should not be separated from drilling fluids engineering or solids control performance. The cooler is one component. The condition of the fluid determines how the system behaves around it.

Operational conditions change the result

Mud cooler performance can look different depending on the operational moment. During steady circulation, temperature trends may stabilise. During connections, flow interruptions, reduced pump rates, wiper trips or changes in drilling parameters, the thermal profile may shift. A reading taken during a transition may not represent stable cooler performance.

A reliable field assessment should consider circulation rate, inlet and outlet mud temperatures, mud weight, fluid type, active system volume, well depth, hole section, cooling-medium conditions, circulation duration, solids loading and any restrictions, bypasses, fouling or flow imbalance through the cooler.

Common evaluation mistakes

One frequent mistake is comparing cooler performance between wells without normalising for flow rate, mud properties and thermal load. Another is assuming that a lower outlet temperature always means better system performance. In HPHT wells, colder is not always the only objective. The objective is controlled and reliable thermal management within the needs of the well and the drilling fluid.

Another mistake is treating the mud cooler as a standalone package. Poor tank circulation, dead zones, incorrect valve line-up, fouled heat-exchange surfaces, insufficient cooling medium and unstable flow distribution can all affect the result. The cooler may be installed correctly, while the surrounding system prevents it from performing properly.

A third mistake is evaluating the cooling requirement too late. If the requirement is reviewed only after surface temperatures are already high, the available corrective actions become limited. Mud cooling should be part of planning and system readiness, not only a trouble response.

A practical assessment approach

A practical mud-cooling assessment should combine field measurements with engineering interpretation. At minimum, it should answer five questions: expected thermal load, measured flow rate and mud properties, stability of mud flow through the cooler, adequacy of the cooling medium, and whether the observed temperature trend fits the well section and operating conditions.

This approach moves the discussion away from a single temperature number and toward a more useful performance picture. It helps determine whether the issue is cooler capacity, fouling, flow distribution, rig system configuration, fluid condition or simply a misunderstanding of what the cooler can realistically achieve under the current operating envelope.

System thinking matters

HPHT wells leave little room for simplified assumptions. Mud cooling, solids control, drilling fluids, hydraulics and surface equipment performance are connected. A weakness in one part of the system can appear as a symptom somewhere else.

Temperature drop matters, but it is only one indicator. True mud-cooling performance is defined by heat load, flow rate, fluid condition, system stability and whether the cooling package is achieving the operational objective required by the well.

The question is not whether a mud cooler can produce an impressive temperature drop on paper. The real question is whether the complete circulating system is being managed well enough to keep the drilling fluid, equipment and operation within a controlled thermal envelope. That is where better evaluation begins.

Further technical reading

For readers looking for additional practical references on mud cooling, drilling fluids and solids control system performance, SC DrillTech maintains a technical knowledge cluster here: https://scdrilltech.com/articles/drilling-mud-cooler-system.html

About the author

Othman Soliman is the Founder of SC DrillTech, an independent technical platform focused on solids control, drilling fluids, drilling waste management and practical field engineering. He has more than a quarter century of experience across drilling operations, equipment performance, rig evaluation, troubleshooting and technical support.

Oil Review Middle East, in association with Flyability is hosting a webinar on “NDT drones for the oil and gas industry: from innovation to implementation" on Tuesday 14 July at 2pm GST

The oil and gas industry continues to face increasing pressure to improve safety, reduce operational downtime and enhance inspection efficiency. Increasingly, operators are deploying drone technology to improve inspection quality, enhance safety and drive greater operational efficiency across oil and gas assets, discovering new ways to conduct inspections in hazardous and confined spaces while minimising risks to personnel.

This practical session will explore how drone technology is being used to perform remote NDT inspections, collect critical asset data and create digital twins that support more effective asset integrity management. Through real-world case studies and industry experience, attendees will gain valuable insights into implementing drone solutions within their own operations.

Register here

Key highlights

• Visual inspections: Learn how drone technology is improving access to difficult and hazardous inspection environments
• Remote NDT applications: Explore the use of UT spot measurements and other remote inspection capabilities
• Digital twins: Understand how digital asset models are supporting integrity monitoring and maintenance planning
• Industry success stories: Hear practical examples from asset owners and service providers successfully utilising drone technology
• Implementation strategies: Gain insights into integrating drone-based inspections into existing operational workflows.

Our expert speakers:

• Fabio Fata, senior sales manager, Flyability
• Senan Khatib, certified AUV pilot/instructor and UAV field specialist Sagerdrone
• Abdullah Al-Rahmah, head of UAV team, Saudi Aramco
• Jacob Swidy, head of inspection technology and digital transformation, Saudi Aramco

Don’t miss this opportunity to take away exclusive insights from the leading lights of the drone technology world!
Register here

Abu Dhabi is forging ahead with hydrogen development and is emerging as one of the world’s leading global hydrogen hubs, according to a new report from the Abu Dhabi Chamber of Commerce and Industry (ADCCI)

The report, entitled Abu Dhabi's Positioning in the Hydrogen Economy, highlights that Abu Dhabi is moving from ambition to concrete project execution through investment in production, infrastructure, manufacturing, logistics and export-oriented value chains, even as progress slows in other markets due to the reassessment of hydrogen ambitions and policy uncertainty.

Competitive advantage

The report finds that the UAE benefits from a unique combination of structural advantages, including:
• abundant solar resources
• efficient electricity infrastructure
• strong industrial capabilities
• low cost of capital, and
• strong project delivery capability.

These factors combine to make Abu Dhabi among the most competitive global hydrogen hubs globally, with the levelised costs of hydrogen and ammonia set to be one of the lowest in the world by 2030, strengthening its position as a key exporter to early demand centres such as the European Union, Japan and South Korea. 

Abu Dhabi has set a 2031 production target of 1.4 Mt/year of low-carbon hydrogen. This is in line with the UAE’s hydrogen strategy, which aims to enhance the UAE’s position as one of the largest producers of hydrogen by that year and envisages the low-carbon fuel as a crucial tool in meeting the country’s net-zero commitments and reducing emissions in hard-to-abate sectors.

Shift to high-value hydrogen derivatives

The report highlights a global strategic shift away from just exporting pure hydrogen toward higher-value derivatives such as green ammonia, methanol, synthetic fuels, and Sustainable Aviation Fuel (SAF).

Abu Dhabi is pursuing a number of initiatives in these areas such as
• Development of methanol and SAF projects using green hydrogen and captured CO₂
• Exploration of e-methane production and bunkering infrastructure
• Expansion into green ammonia and synthetic fuels.

These initiatives could result in exports worth millions of dirhams, as well as creating new jobs and contributing to emissions reduction, creating new opportunities across manufacturing, trade, logistics and industrial production.

Offtake agreements critical

The report stresses that long-term offtake agreements are critical to accelerate investment and scale the hydrogen economy. As a recent IEA report notes, demand uncertainty remains a key constraint for scaling up low-emissions hydrogen development, and is cited by developers as one of the largest barriers to investment. Despite strong global momentum, the report notes that only around 12% of low-carbon hydrogen projects have secured confirmed customers.

Addressing these considerations, Abu Dhabi is demonstrating a viable delivery model through customer-aligned projects and partnerships:
• The EMSTEEL–Masdar green steel pilot (MENA’s first hydrogen-based steel project) is already operational
• Offtake agreements have been signed with Modon and Aldar to supply green steel to sustainable construction projects.

Equipment and technology offer opportunities

As well as production and derivatives, the report identifies opportunities in exporting hydrogen-related technologies and equipment to global projects, such as electrolysers, port infrastructure components and blending projects. Abu Dhabi's industrial zones — including KEZAD— and logistics infrastructure at Khalifa Port position the emirate as a manufacturing and re-export hub to markets such as China, Germany, the United Kingdom, the USA, and Australia. In a regional first, ADNOC, John Cockerill Hydrogen, and Strata Manufacturing signed an agreement in 2023 to produce electrolysers in the UAE for domestic use and export. Other similar arrangements will surely follow.