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Joint Oil Exploration, Exploitation and Petroleum Services Company (Joint Oil), a joint venture between Libya and Tunisia, has announced the opening of a new bid round on 7 September for development of the promising Zarat discovery and further exploration of the Joint Oil Block border acreage

Located in the prolific Gabes-Tripoli Basin of the central Mediterranean, this offshore acreage represents a premier opportunity for cross-border energy cooperation between Tunisia and Libya. Moyes & Co., a global upstream advisory firm, has been engaged to seek industry partners for two separate commercial packages:

• Exploration: Further exploration of the Joint Oil Block for new plays, leads, and prospects under an Exploration and Production Sharing Agreement (EPSA). The area concerned spans 3,000 sq km in water depth of 80-120m, with seismic data covering 6,500km of 2D & 1,900km of 3D. Wells: Zohra-1 (1976), El Amal South 1 (1999), Besmah-1 (2002), El Amal North 1 (2002), Zarat North 1 (2010). Surrounding producing fields: El Bouri, El Jurf and Bihr El Salam in Libya; Hasdrubal, Ashtart, Miskar & Didon in Tunisia.

• Development: Development of the Zarat Discovery — which straddles the Tunisia-Libya border— as a unitised oil and gas resource. This will be governed by a Development and Production Sharing Agreement (DPSA), Unitisation Agreement (UA), Unit Operating Agreement (UOA), and Operating Services Contract (OSC).

The bid round will close on 31 December 2026.

Credible companies with proven offshore exploration and development capability are invited to apply for access to the Virtual Data Room (VDR) managed by Moyes. Bids must be received by 8 January 2027. Winning bidders will be informed by 26 February 2027, with formal awards expected by 30 April 2027.

The bid round opportunity will be presented at the London Mediterranean, Middle East & Africa Scout Group (MMEA) on 9 September 2026 and at the World Energy Summit in London on 29-30 September 2026 where Joint Oil will also be present at a booth.

Strong potential

Joint Oil has highlighted the exceptional potential of the Joint Oil Block and the Zarat Discovery, strategically positioned along the southern margin of the Pelagian Basin within the geological extension of the Sabratha–Gabes Basin. 

The concession benefits from a highly strategic offshore location near several major producing fields across the Sabratha–Gabes Basin, including Al Jurf, Bahr Essalam, and Bouri offshore Libya, as well as Ashtart, Didon, and Miskar offshore Tunisia. This positioning enhances the project’s long-term value proposition through access to established regional infrastructure, operational synergies, and export pathways.

Bordered by active Libyan exploration zones and major offshore concessions, the Joint Oil Block and Zarat discovery further underscore the substantial untapped hydrocarbon potential of the shared Tunisian-Libyan offshore basin, reinforcing its attractiveness as a high-impact exploration and development opportunity for investors and strategic partners. Zarat is the largest discovery in offshore Tunisia since the Miskar discovery in 1975, and is the largest undeveloped field in offshore Tunisia. Contingent resources at Zarat attributable to the Joint Oil Block totals 158 mmboe.

Joint Oil is a joint venture between Libya and Tunisia through the national companies, the Tunisian Corporation of Petroleum Activities (ETAP) and Ola Energy Holdings Ltd. (OLA Energy). The company has managed hydrocarbon resources within the Tunisia-Libyan offshore acreage since 1988.

SLB has been awarded four integrated well construction contracts by Aramco to support oil and gas development across the Kingdom of Saudi Arabia

Under the contracts, SLB will manage end-to-end well construction services, delivering more than 450 wells over the three-year term, with an optional extension of up to two years.

What is integrated well construction?

As projects become larger and more complex, integrating planning, execution and digital workflows helps to reduce operational costs, speed up delivery, and minimise risks. In Namibia, an integrated well construction campaign cut the award-to-spud cycle by 67%, from a traditional 18-month timeline to six months.

Streamlined approach

Integrated well construction brings together engineering, drilling, and completions into a single, streamlined approach to well design and execution, through a technology-enabled operating model. It combines digital drilling workflows with automated drilling, evaluation, fluids, cementing, and completions products and services to improve efficiency, consistency, and well performance across diverse, large-scale drilling programmes. Integration ensures that information flows seamlessly throughout the organisation, without silos.

Planning to execution expertise

SLB’s well engineering expertise optimises every phase—from exploration to full field development—through strong risk management and operational oversight. This enables the delivery of safe, efficient, and precise outcomes tailored to the customer’s reservoir challenges.

Leading technologies

SLB combines advanced well construction technologies with fit-for-purpose solutions to improve performance and set new standards in execution.

Digitally enabled workflows

From autonomous drilling to AI-driven decision-making, digital solutions drive smarter, faster, and more reliable results.

"Delivering hundreds of wells across a multi-year programme and in multiple operating environments requires an integrated model that connects planning, execution, and digital workflows to set new industry performance benchmarks,” said Steve Gassen, executive vice president of Geographies for SLB. “Awarding SLB these advanced well construction programmes at scale reflects Aramco’s confidence in our integrated model and capabilities."

Building on the longstanding collaboration between SLB and Aramco, the awards represent a significant expansion of SLB's integrated well construction business in the Kingdom and reflect growing customer adoption of integrated delivery models for large-scale drilling programmes, highlighting the model’s ability to improve execution consistency across the well construction lifecycle. It comes as Aramco continues to pursue major projects to maintain maximum sustainable capacity at 12mn bpd, such as the Zuluf crude oil increment project and the Dammam development, as well as to grow gas production capacity by around 80%, with a focus on unlocking its unconventional gas resources. SLB was awarded a five-year contract by Aramco to provide stimulation services for its unconventional gas fields earlier this year.

TA’ZIZ, a joint venture between ADNOC and ADQ, has signed long-term agreements spanning offtake, feedstock and sales across its chemicals portfolio, valued at US$28.5bn (AED104.6bn)

Signed at the Make it in the Emirates Forum, the agreements, valued at US$28.5bn, secure both global offtake and reliable local feedstocks, allowing for large-scale chemical production within the UAE and reinforcing TA’ZIZ’s role in building a fully integrated domestic chemicals ecosystem. The deals include sale agreements with ADNOC and Proman for methanol; Emirates Global Aluminium (EGA) for caustic soda; Mitsubishi Corporation for ethylene dichloride (EDC), vinyl chloride monomer (VCM) and caustic soda; Mitsui & Co. for EDC and caustic soda; Sanmar Group for EDC and VCM; Tricon for PVC, EDC and caustic soda; and Vinmar for EDC and polyvinyl chloride (PVC).

ADNOC Gas secured a 25-year feedstock agreement to supply natural gas to the TA'ZIZ methanol project valued at over $5 billion (AED18.4 billion). TA’ZIZ also agreed a 20 year salt supply agreement with Abu Dhabi based Sama Salt to support production at its PVC complex.

Mashal Saoud Al-Kindi, CEO of TA’ZIZ, said, “These long term agreements represent a defining milestone for TA’ZIZ and for the UAE’s industrial growth ambitions. By securing both global demand and reliable local feedstock, we are translating vision into delivery, anchoring world scale chemicals production, strengthening domestic value chains and creating enduring economic value, jobs and supply chain resilience for the UAE.”

Together, these agreements leverage local resources to secure a reliable and sustainable supply of critical raw materials, further strengthening domestic value chains and advancing the UAE’s industrial self sufficiency.

TA’ZIZ is a manufacturing, industrial services, logistics and utilities ecosystem that enables the production of transition fuels and new products across the chemicals value chain, supporting ADNOC’s ambition to become a top three global chemicals player as well as the UAE’s industrial development and economic diversification ambitions.

The TA’ZIZ Industrial Chemicals Zone is set to produce 4.7 million tonnes per annum (mtpa) of chemicals once construction is completed in 2028. This includes a 1 mtpa ammonia plant, a 1.8 mtpa methanol plant and 1.9 mtpa of marketable products from its integrated polyvinyl chloride (PVC) complex. The PVC complex, which produces PVC, ethylene dichloride (EDC), vinyl chloride monomer (VCM), and caustic soda, will be one of the world’s top three largest single site PVC complexes.

Also at the Make it at the Emirates Forum, TA’ZIZ and Alpha Dhabi Holding announced a strategic collaboration agreement for around US$10 bn (AED36.7bn) in capital investment in new industrial chemicals in the TA’ZIZ industrial chemicals ecosystem in Al Ruwais Industrial City, Al Dhafra region of Abu Dhabi.

The partnership could produce up to 14 new chemicals, delivering around 2.2mn tonnes per annum (mtpa) of additional chemical capacity in the TA’ZIZ industrial chemicals ecosystem in Al Ruwais Industrial City. The new chemicals, which include styrene and polystyrenes, acrylic acid and derivates, polyols, MDI, epoxy resins and linear alpha-olefins, are based on domestic demand and could substitute key products currently imported into the UAE, while strengthening local supply chain resilience. The partnership supports the UAE’s national industrial priorities, including the Make it in the Emirates (MIITE) initiative and the country’s industrial strategy, by strengthening domestic manufacturing capability and advancing self-sufficiency in strategically important chemical products.

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.

How do complacency and human factors contribute to workplace injuries, and how can you prevent complacency-related injuries and incidents?

That is the subject of a webinar hosted by HSE Review in association with SafeStart, to take place on Wednesday 1st April 2026 at 2pm GST, which will shine a light on the neuroscience behind competence, complacency and human factors.

Safety professionals have known for years that “complacency is a silent killer.” They have also suspected that complacency was a contributing factor in almost every unintentional injury or incident. Unfortunately, from a neuroscience perspective, it is impossible to stop people from becoming complacent once they are competent. And for high-risks tasks in particular, competence is a must.

Even more unfortunately, many (most) companies do not know what to do to help their employees deal with complacency, which leads to mind not on task/risk.

In this session, participants will:
• Understand the neuroscience behind complacency and why it cannot be eliminated once competence is achieved
• Recognise the two stages of the complacency continuum and how human factors impact critical decision-making
• Learn practical skills to prevent complacency-related injuries, including attentive habits, looking for risk patterns in others, analysing close calls and small errors to prevent agonising over large ones, and using self-triggering skills, to deal with rushing, frustration and fatigue which, when combined with complacency, can cause fatalities
• Explore how concepts such as fail-safe can help compensate for complacency leading to mind not on task.

Register for the webinar here

Our speaker is Larry Wilson, a pioneer in the area of Human Factors in safety. He has been a safety consultant for over 25 years and has worked on-site with hundreds of companies worldwide. Larry is the author of SafeStart, an advanced safety and performance awareness programme, successfully implemented in more than 4,500 companies in 75 countries, with more than five million people trained. He is the moderator of the SafeConnection expert panels series and has authored and co-authored a number of books, the latest being “25 Years of Original Thought-Innovations in Safety, Human Error and Performance”. Larry is also an active keynote speaker at health and safety conferences around the globe (32 countries so far).

Participants are guaranteed an hour of engaging and thought-provoking interactive discussion and debate and will take away the understanding, skills and strategies to help prevent complacency-related injuries and incidents.

So don’t delay, register for the webinar here

SafeStart Trainer Certification – Global Training Series

Following strong demand last year and impact across global markets, we’re also launching the SafeStart Trainer Certification – Global Training Series, starting with Dubai on 7–8 April 2026.

This is a practical, human factors–based certification designed to help organisations reduce incidents, strengthen decision-making, and improve overall safety performance, on and off the job.

Find out more information and register here:

DNV has published a recommended practice (RP) for offshore hydrogen pipelines, supporting safe design, operation and requalification of pipeline infrastructure for transporting hydrogen

DNV-RP-F123 Hydrogen pipeline systems addresses hydrogen-specific integrity and safety considerations. It supplements DNV’s established submarine pipeline standard, DNV-ST-F101 and adds additional guidance tailored to transporting hydrogen gas and hydrogen blends in pipeline systems. It is relevant for new pipeline developments as well as for the requalifying of existing offshore infrastructure for hydrogen transport, supporting broader efforts to scale hydrogen networks.

Hydrogen is expected to play an increasing role in cutting emissions from hard-to-decarbonise sectors. However the transportation of hydrogen by pipeline faces certain risks and considerations, such as embrittlement.

DNV-RP-F123 has been developed through the H2Pipe joint industry project (JIP), which ran from 2021 to 2026 and brought together 37 industry partners across operators, manufacturers, engineering companies and academic advisors to provide guidance for engineering projects and qualification work.

The next step is large-scale testing to validate data and advance existing standards. This phase will include full-scale pipe testing at DNV’s Spadeadam Research and Development Facility. The results will feed into the continued development of DNV-RP-F123 and future guidance.

“Hydrogen service fundamentally changes the integrity picture for pipeline systems,” explained Prajeev Rasiah, executive vice president and regional director for Northern Europe, Energy Systems at DNV, “it cannot be treated as a simple variant of natural gas. This recommended practice moves beyond theoretical study to provide an evidence-based framework for assessing hydrogen-specific risks in design, requalification, and operation. By closing the gaps around material suitability and safety margins, we are giving teams the technical clarity needed to move projects from the study phase into execution. This is particularly vital for requalifying existing infrastructure, where the guidance helps define exactly what must be tested or upgraded to ensure a safe reliable and sustainable transition.”

“The objective of the H2Pipe JIP is to build guidance grounded in shared data and real technical experience from testing,” added Philippe Darcis, chairman of the H2Pipe JIP Steering Committee and Pipeline Technology Senior Director at Tenaris. “The real value of the H2Pipe JIP is in turning years of shared data into credible, site-ready guidance that engineers can use to scale hydrogen infrastructure. This is a practical tool built to reduce the 'unknowns' that often stall investment. Because it was developed through industry-wide collaboration, it gives operators a robust basis for making decisions, allowing us to move forward with fewer assumptions and greater confidence in our safety and performance standards.”