International Oil & Gas Engineer October 2026 by Setform Ltd

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BEYOND

The challenges facing Europe’s gas resilience

WHERE THERE’S SMOKE...

MAPPING IT OUT

Specifying cable penetrations for hydrocarbon and jet fires

Peformance-based mapping is taking hold in the Middle East

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CONTENTS

Welcome As we prepare for 2027, the oil and gas industry is facing numerous challenges. Geopolitical tensions, threats to energy security and economic uncertainty are casting shadows over the sector and prompting overdue discussions. The topic of resilience is present throughout this edition. In the cover story (page 6), our reporter explores how Europe’s gas resilience depends on so much more than simply having enough of it. The article examines how targeted upgrades to ageing infrastructure can help networks save money and avoid risk. Moving from Europe to the Middle East, we hear from Micropack’s managing director Graham Duncan, who explains why performance-based mapping is changing fire and gas detector layouts across the region. Mapping also comes up on page 10, where a 3D mapping tool is changing how oil and gas companies approach hard-to-reach reservoirs, first in Kuwait and now across the globe. The digitalisation of maintenance and operations is more prevalent than ever. Page 16, 27, and 30 all feature recent advances in continuous and predictive monitoring. Elsewhere, Eliot Sizeland from Fire & Gas Technologies, Inc. shares valuable insights from his career in fire and gas detection solutions (page 50), and Henkel Adhesive Technologies’ Dinko Cudic discusses what decades of infrastructure protection and repair have taught him (page 20). Saskia Henn Editor

– OCTOBER 2026 – COVER

Beyond supply

Q&A: Offshore asset integrity Henkel’s Dinko Cudic on how to maintain offshore infrastructure

Exploring the challenges facing Europe’s gas resilience

EXPLORATION • DRILLING • FIELD SERVICES

10 12

Below the surface Examining 3D mapping tool AlphaSight

A real-time solution How AI is helping autonomous well construction

Making waves How Halliburton is expanding its involvement in a major gas development in Cyprus

The path forward How digitalisation is changing the equation

Clean coverage A remote way to tackle fired heater fouling

Going green Continuous emissions monitoring could boost offshore oil and gas efficiency

OPERATIONS & MAINTENANCE

Advanced sensors How real-time corrosion monitoring can make a difference

27 www.engineerlive.com

CONTENTS

Where there’s smoke… Specifying cable penetrations for hydrocarbon and jet fires

PRODUCTION • PROCESSING

Fail-safe Rotork’s actuation for tank and terminal operations

Every connection counts look at modern lifting A operations

Growing together Examining the impact of Bangkok’s Gastech 2026

The hidden challenge hy synchronous condensers W and BESS must work together in weak-grid operations

A fresh approach Why reliquefaction does not

Complex, not costly

From the industry: Eliot Sizeland Fire & Gas Detection Technologies’ Eliot Sizeland shares valuable insights from his career in fire and gas detection solutions

Mapping it out How performance-based mapping is changing fire and gas detector layouts in the Middle East

HEALTH & SAFETY

54 56

mall accessories, S big impact Getting the most out of Ex-certified devices

Under pressure The value of QCDC technology in shallow and deep-water operations

SKILL ZONE

Certified sessions How Nigeria is incorporating training into its surging oil and gas industry

Avoidable explosions A2E’s David Ross explores key safety considerations for electronic equipment

Specialist skills

SUBSEA TECHNOLOGY

A defining moment

A look at the first DNVcertified lifting point for subsea operations by RUD

How to enable more autonomous and efficient subsea energy storage

As UK oil and gas workers brace for uncertainty, the government gets involved

SHOW PREVIEW

Packing power

have to be complicated

Why complex topside specifications need not carry bespoke pricing

acing the crucial F conversations ADIPEC goes forward with an updated programme

A timely transition OEEC2026 opens at Amsterdam RAI in November

PUBLISHER Jerry Ramsdale EDITOR Saskia Henn shenn@setform.com DESIGN – Dan Bennett, Jill Harris HEAD OF PRODUCTION Luke Wikner production@setform.com HEAD OF SALES & PARTNERSHIPS David Pattison ACCOUNT DIRECTORS John Abey | Peter King SENIOR ACCOUNT MANAGERS John Davis | Darren Ringer | Roy Glasspool ACCOUNT MANAGERS

Setform’s international magazine for engineers is published twice annually and distributed to senior engineers throughout the world. Other titles in the company portfolio focus on Process, Design, Transport, Mining, Energy and Power. The publishers do not sponsor or otherwise support any substance or service advertised or mentioned in this book; nor is the publisher responsible for the accuracy of any statement in this publication. ©2026. The entire content of this publication is protected by copyright, full details of which are available from the publishers. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner.

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BEYOND SUPPLY The challenges facing Europe's gas resilience

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COVER STORY

Up-to-date regulators are critical in the oil and gas industry to ensure operational safety, precise efficiency, and strict environmental protection

BEYOND

SUPPLY

Lydia Arundel explores the challenges facing Europe’s gas resilience

iscussions around Europe’s gas resilience often focus on whether enough gas will be available to meet winter demand, with storage levels, imports and LNG supplies coming under scrutiny. Having available gas is only part of the puzzle, as Faris Churcher, UK engineering company Oxford Flow’s business lead for Gas & Energy Transition, puts it: “You store gas, you move gas, you use gas.” Gas needs to be transported through networks that were designed, in some cases, decades ago, and the equipment controlling its flow and pressure needs

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Faris Churcher, UK engineering company Oxford Flow’s business lead for Gas & Energy Transition

to remain available, maintainable, and adaptable as the energy system changes.

BEYOND STORAGE

With Europe approaching another winter, gas storage levels are attracting attention. Recent figures from Global Energy Flow put EU gas storage at 68.04% full as of 13 September, below the seasonal average. These figures highlight the importance of gas system resilience, but storage is only one part of the equation. Gas has to travel through pipelines and pressure-control infrastructure before reaching its end use.

Churcher points to pressure reduction stations, regulators, flow-control valves and compressor stations as examples of the equipment that sits between stored or imported gas and its eventual use. He shares: “If you put a load of money into your storage, but you don’t upgrade the pipelines or the flow control devices or the pressure reduction stations, you might have the gas, but you might not be able to move it.”

THE CHALLENGE OF AGEING EQUIPMENT For network operators, ageing equipment is not necessarily a

COVER STORY

question of replacing an entire system. Churcher describes it instead as a balance between asset management, maintenance and investment. Network operators have finite budgets and cannot replace every ageing component, so they must decide which assets are most critical. Pressure-control equipment is one area where this can become particularly important. Some equipment in gas networks has been in service for decades. As manufacturers stop producing particular components and specialist skills and spare parts become harder to source, maintaining legacy equipment can become increasingly complicated. The result is a balancing act between wholesale replacement and targeted intervention. Churcher argues for the latter approach: identify critical components, replace those where necessary, and maintain and reuse parts of the existing system that remain suitable. This approach becomes relevant as the gas system changes, with existing infrastructure having to accommodate different operating requirements without operators having the option or need to replace the entire network.

A CASE STUDY BENEATH THE SURFACE

Oxford Flow’s work with UK gas distribution network Cadent Gas illustrates this approach. The two companies have collaborated for three years to develop and implement PRISM, the Pressure Reducing Integrated Subterranean Module. The technology is intended to replace legacy ERS modules used in Cadent’s network. The original ERS technology dates back to the 1970s, when the Engineering Research Station and British Gas developed equipment intended for top-up regulation before it was deployed more widely across the gas network. Over time, that equipment became part of the UK gas network’s backbone. Churcher explained that the organisation responsible for the original technology no longer maintains or produces the same spares, so maintaining some legacy equipment now requires specialist facilities and skills.

Oxford Flow and Cadent have collaborated for three years to develop and implement PRISM

PRISM is designed to reuse what can be retained while replacing the main regulator with Oxford Flow’s IMS regulator, avoiding the need to replace the surrounding infrastructure. Oxford Flow says the retrofit approach can also reduce replacement costs. Churcher puts the average cost of replacing the relevant equipment at around £60,000, with PRISM reducing that cost by almost 60%. Those figures are Oxford Flow’s own estimates, but they illustrate the wider argument that extending the useful life of existing infrastructure does not necessarily mean leaving obsolete equipment untouched.

RELIABILITY WITHOUT WHOLESALE REPLACEMENT The practical value of that approach becomes clearer when critical equipment requires intervention. Churcher describes failures as existing on a spectrum, with gas networks already incorporating redundancy, alarms, safeguards and standby arrangements. A failure does not automatically put the wider network at risk. The challenge can instead be operational. A problem with ageing equipment can lead to callouts, specialist maintenance requirements and long lead times for particular materials.

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COVER STORY

Churcher cites lead times of 16 to 20 weeks or more for some specific materials. Maintenance itself can also have consequences. Churcher points to situations where servicing or decommissioning equipment requires depressurising sections of the gas network, potentially venting methane. For Churcher, that adds another reason to focus on reliable, repairable equipment.

A EUROPEAN ISSUE

The challenge is not confined to the UK. Churcher says similar issues with ageing pressure-control and flow-control equipment exist across European gas networks, pointing to examples in countries including the Netherlands, Germany, Austria and Ireland. Some regulator designs have been in use for many decades. Churcher cites Dutch gas infrastructure using older “jet stream” regulators originally designed in the 1940s and says similar questions around dwindling spares and obsolete equipment are emerging elsewhere. The wider point is that network obsolescence is an asset management challenge that extends beyond any one operator or country. That does not mean European gas networks are inherently unsafe because they contain ageing equipment. Churcher was clear that gas infrastructure has redundancy and safeguards in place. The concern instead is around what happens as equipment becomes increasingly difficult to maintain, source, or replace. For operators, this means the question shifts to when to intervene and how much of the existing infrastructure needs replacing.

PREPARING FOR A CHANGING GAS MIX

This question becomes more complicated as Europe considers the future role of gases such as biomethane and hydrogen. Churcher gives the use of hydrogen as an example of why existing infrastructure may need to evolve. Converting existing pipelines for hydrogen raises another question around the suitability of individual components, including pressure-control

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Regulators are one of the pieces of equipment that sit between stored or imported gas and its eventual use

equipment. Hydrogen’s properties mean components designed for conventional natural gas cannot be assumed to have the same requirements. Again, Churcher’s argument is not necessarily for wholesale replacement, he sees an opportunity to identify which components need to change while retaining as much of the existing infrastructure as possible. That approach could become more relevant if networks need to accommodate different gases or changing operating conditions while making use of infrastructure that still has useful life remaining.

TARGETED INVESTMENT

Ultimately, the decision comes down to asset criticality, available budgets, and the regulatory framework governing network investment. Churcher stated that, in the UK, OFGEM price-control periods are important to the process for network operators, determining whether assets should be fully replaced, have individual components replaced, or continue to be maintained. The sites that are most critical to

the operation of the network, Churcher argues, are where investment can have the greatest value, making targeted upgrades potentially important during a period when network operators are managing ageing assets while also considering how existing infrastructure fits into the energy transition. Instead of treating an ageing network as something to be replaced entirely or left untouched, operators can assess where intervention is actually needed.

KEEPING GAS MOVING

Europe’s gas resilience depends on more than having enough gas in storage; it also relies on infrastructure that can move and regulate it when needed. As networks face ageing equipment, tight budgets and a changing gas mix, targeted upgrades can help operators strengthen critical assets without replacing entire systems. Having the gas is only the start; resilience depends on being able to move it.

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EXPLORATION, DRILLING, FIELD SERVICES

BELOW THE

SURFACE

A 3D mapping tool is changing how oil and gas companies approach hard-to-reach reservoirs AlphaSight allows operators to see ahead of the bit for precise well placement

apping underground oil and gas reservoirs can be a difficult and expensive process. Subsurface data can be patchy or difficult to decipher, leaving geologists to interpret complex geology using limited information. Unconventional formations, micropores and underground variations are just some of the variables that can impact the mapping process. Without effective mapping, geosteering is difficult as well. Operators adjusting a wellbore’s trajectory in real time must navigate subsurface characteristics based on extremely limited data and visibility. The challenge of mapping and geosteering for subsurface conditions will only become more prevalent as large, easily accessible oil and gas reservoirs deplete. What remains is deeper, smaller targets with tight rocks and fractured formations. These reservoirs will already be more expensive to extract from by requiring more advanced technology, so the accurate identification and

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mapping of potential deposits is crucial to cost savings and operational efficiency.

THE POTENTIAL OF ALPHASIGHT

Technology companies are scrambling to address the question of how modern extraction tools can be tailored to handle complex geological challenges. One solution comes from energy technology company SLB. SLB launched AlphaSight earlier this year, a 3D reservoir mapping solution and geosteering technology providing real-time subsurface visibility during complex drilling operations. The solution uses advanced physics-based EM measurements. Its measurement system centres on a triaxial, collocated transmitter and receiver antenna arrangement. The multi-depth azimuthal resistivity (MDAR) technology platform increases both depth of detection and vertical resolution around the wellbore and ahead of the bit. Operating across 11 frequencies from 1MHz to under

1kHz, AlphaSight resolves boundaries and thin beds that conventional tools can miss. Operators can use AlphaSight to see subsurface characteristics more clearly and at significantly further depths than conventional, noncollocated, tilted-antenna (LWD) tools. By expanding petrophysical insight and accelerating geosteering decisions, the technology supports faster, more accurate well delivery. “It’s not just an incremental improvement, but a complete transformation in well placement,” said SLB president of Well Construction, Cecilia Prieto. “With unprecedented resolution, depth, and look-ahead capabilities, AlphaSight, empowers operators with clarity to make more confident decisions and achieve greater production than ever before.” According to SLB, AlphaSight can help operators navigate complex reservoirs across every resistivity environment, including low-resistivity, low-contrast and high-resistivity, lowcontrast formations.

EXPLORATION, DRILLING, FIELD SERVICES

By leveraging the LA3D, the well was landed successfully within 1ft of the reservoir top, achieving Kuwait Oil Company’s geosteering objective without sidetracks

FIELD TESTING IN KUWAIT

AlphaSight has undergone field tests across the Middle East, North Sea, North America and Asia. In field deployments, the technology has landed a well within 1ft of the reservoir top in a layered carbonate reservoir and detected structural boundaries up to 75ft ahead of the bit, giving geosteering teams more time to react to changing formation conditions. In a layered carbonate reservoir in Kuwait, for example, Kuwait Oil Company wished to land a gasproducing well with precision while maintaining drilling performance in a section with 8°/100 ft DLS. The formation’s low resistivity contrast between laminations reduced the effectiveness of conventional azimuthal resistivity tools.

AlphaSight landed the gasproducing well within 1ft of the reservoir top. Real-time inversion outputs of RMI and ABI enabled faster and more confident steering decisions under dynamic formation conditions, while the delineation of thin laminated layers improved, allowing higher-precision placement in a low-contrast environment. The operation also maintained consistent RSS performance under 8°/100 ft DLS. Compared to a conventional pseudotriaxial, noncollocated, ultradeep system, AlphaSight showed improved boundary clarity, finer vertical resolution and reduced interpretation uncertainty by up to 50%. Kuwait Oil company also used AlphaSight for its Sabriyah field, where it was experiencing difficulties drilling horizontal wells. The drilling

ENVIRONMENTS WHERE CONVENTIONAL RESISTIVITY TOOLS STRUGGLE • Complex or thin-bed reservoirs • High-angle and extended-reach wells

environment was full of unknown fault locations, vertical displacements and extended overburden for shale, making geosteering difficult. Legacy drilling technologies simply failed to deliver the required sensitivity and real-time imaging. SLB again deployed AlphaSight, and the platform’s triaxial, collocated antenna arrays provided 3D resistivity mapping, capturing directional measurements across shallow, medium, deep, and ultradeep spacings. This enabled the detection of structural changes up to 75ft ahead of the bit, supporting timely trajectory adjustments and reduced risk of stuck pipe incidents. “The high-resolution imaging and real-time data delivery allowed us to make proactive decisions, significantly improving drilling efficiency and reservoir contact,” says Fayez Al-Fayez, senior geologist, Kuwait Oil Company.

LOOKING AHEAD

As oil and gas reservoirs become increasingly complex and difficult to locate, the effectiveness of mapping tools is key to helping operators make informed decisions.

• Offshore and deepwater development • Low-resistivity shale and alt-adjacent formations • Relief well planning and anticollision ranging • Infill and field development wells

For more information visit: www.slb.com

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EXPLORATION, DRILLING, FIELD SERVICES

A REAL-TIME SOLUTION An autonomous well construction solution is providing intelligent operations in the field

Kantori applies internal logic and standardised execution to make consistent, real-time decisions with limited human oversight

s wells become more complex, operators are grappling with processing increasing amounts of data. They are also faced with the need for faster decision-making while minimising the inherent risk of working in the field.

Kantori supports the whole well construction life cycle

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Earlier this year, to address these concerns, Energy technology company Baker Hughes launched Kantori, an autonomous well construction solution. Kantori supports the whole well construction life cycle, from connectivity and data integration to well planning and performance

optimisation. The adaptive optimisation tools manage hydraulics, fluids and operating parameters to maintain stability, reduce downtime and limit operational risk. Kantori uses AI and physics-based models, as well as real-time data analytics to continually optimise

Kantori uses AI and physics-based models to optimise performance

EXPLORATION, DRILLING, FIELD SERVICES

APPLICATIONS FOR KANTORI • Wells with inconsistent or unpredictable drilling performance • Narrow pressure windows or complex subsurface conditions • Development programmes requiring repeatable execution • Remote and reduced personnel operating models Kantori makes well construction smarter, safer and more predictable

performance, while enabling automation across planning, execution and monitoring activities. It is scalable, assisting in the design of a single well or across an entire field. “Autonomous drilling has opened new frontiers for our industry, replacing reactive operations with intelligent systems that can learn, adapt and optimise performance in real time,” said Amerino Gatti, executive VP, Oilfield Services & Equipment at

Baker Hughes. “This digitally-driven approach, built on decades of drilling expertise and intelligent engineering, is making well construction smarter, safer and more predictable.” Corva, a real-time cloud and AIpowered data analytics platform, supports the real-time nature of the technology. It enables quick decisionmaking in the field with limited human intervention, which could reduce downtime and variability

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EXPLORATION, DRILLING, FIELD SERVICES

MAKING WAVES Cronos gas field is approaching active operations in 2028 with a contribution from Halliburton

ocated about 115mi southwest of Cyprus in the Mediterranean Sea lies the Cronos gas field, the country’s first major upstream natural gas development project. The Cronos gas field offshore development is expected to contain over 3ctf of gas in place. Discovered in 2022 and appraised in 2024, the venture reached a final investment decision in July 2026. Now what follows is the introduction of drilling, well construction and automation.

Production is expected to begin in 2028, with a plateau of around 500m³ ft per day

HALLIBURTON’S CONTRIBUTION

Halliburton recently secured a bundled well construction and completions contract with Eni for the Cronos ultra-deepwater development in Block 6 of the Cyprus Exclusive Economic Zone. “The award strengthens Halliburton’s position in the Eastern Mediterranean, one of the industry’s most active emerging offshore gas regions,” says Jean-Marc Lopez, senior VP, Europe, Eurasia and Sub-Saharan Africa, Halliburton. “The company expects its integrated delivery model to support future development as operators prioritise efficiency, performance, and long-term value. Under the contract, Halliburton will deliver integrated drilling, well construction, automation and completion services for exploration and development wells. The bundled scope reduces operational interfaces, improves execution certainty, and supports efficient delivery for a multiyear ultra-deepwater development. The scope includes drilling fluids, directional drilling, LOGIX automation and remote operations, cementing, surface well testing and coiled tubing. Halliburton will support the efforts through its established infrastructure and regional capabilities in Cyprus, which provide logistical advantages and help ensure reliable execution throughout the campaign.

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Eni aims to bring the first Cypriot gas to market in 2028. Production is expected to reach a plateau of 500 mmscf/d. Gas will be transported and processed in existing Zohr facilities in Egypt, and then transferred and liquefied in Damietta LNG plant for export as LNG to international markets, primarily Europe. “Cronos fast-track initiative marks a concrete milestone in positioning Cyprus as a European gas producer and exporter and it unlocks the establishment of a regional gas hub in the Eastern Mediterranean by leveraging Egypt’s existing hydrocarbon infrastructure,” says Eni CEO Claudio Descalzi. “It is furthermore an example of international cooperation and a concrete contribution to the diversification and security of Europe’s gas supply.” Eni has been present in Cyprus

since 2013. Block 6 is operated by Eni holding 50% interest, with TotalEnergies as partner. In the Country, Eni also operates Block 8 and has participating interests in Blocks 7 and 11, operated by TotalEnergies. “This new gas route in the Mediterranean will contribute to Europe’s energy security by diversifying its LNG supply sources” says Patrick Pouyanné, chairman and CEO of TotalEnergies. “By relying on existing gas processing capacities, this project is aligned with our strategy of prioritising low-cost and low-emission projects. Cronos will also contribute to the growth of TotalEnergies’ LNG portfolio which is expected to reach 60 Mtpa by 2030.”

For more information visit: www.halliburton.com

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OPERATIONS & MAINTENANCE

ADVANCED SENSORS How real-time corrosion monitoring helps prevent pipeline failures, by SMARTCORR’s Dauren Kazimbek

Dauren Kazimbek has 25 years of experience in oil and gas asset protection

orroded pipes are hazards that affect the safety and function of the people and systems surrounding the pipework. Tracking pipe corrosion used to be a complicated process that required manual labour and occasional destructive testing. Maintenance was less effective and often reactive, prompting professionals to fix problems as they

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arose instead of preventing them. Newer innovations help to keep the surrounding structures intact and maintenance crews safe, while providing critical data about the status of the pipework. With this guide, technical professionals will better understand how the integration of real-time corrosion monitoring can lead to fewer pipeline failures.

OPERATIONS & MAINTENANCE

Preventing corroded pipes requires a combination of protective coatings, chemical treatments, and active electrochemical controls

ADVANCED SENSORS

Modern pipeline monitoring requires advanced sensors and machine learning algorithms to process the massive amount of data provided by the sensors. These sensors track conditions around the pipes, generating alerts about leaks or changes to pipe thickness to indicate a possible corrosion defect. Since the sensors regularly record

information about the condition of the pipeline in a specific area, maintenance crews receive regular updates that they can compare to build a track record. Integration of an artificial intelligence system is often required for proper processing, as manual evaluation often fails to analyse the data quickly enough to prevent a problem occurring.

CONTINUOUS MONITORING

The shift from reactive to proactive maintenance and repair requires more attention to inspections and monitoring. Sensors provide routine data about pipe condition at set intervals to establish a baseline condition and evaluate its progression over time. This data offers retrospective

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OPERATIONS & MAINTENANCE

In the oil and gas industry, corrosion can lead to expensive failures and environmental liabilities

Corrosion occurs when the metal reacts chemically or electrochemically with its environment

information that can inform predictive maintenance plans and datadriven insights for future pipeline implementations but also provides critical warnings in real-time. Maintenance crews can get advance notice that a pipeline is starting to corrode, so they can seek additional testing or perform repairs before the pipe leaks.

and leaks before they happen. Predictive maintenance is a critical function within this framework, unique because it utilises data from existing inspections and past monitoring to generate maintenance needs for each pipeline. Maintenance crews can set schedules to perform routine upkeep and visual inspections of problem zones, minimising service interruptions or downtime. As a result, pipes at greater risk for corrosion and leaks can receive more attention and faster responses to anticipated failures.

IN-LINE INSPECTION TECHNOLOGIES

In-line inspection technologies are an innovative practice for monitoring and testing systems as they operate, without damaging the structures around the system. Two common inline inspections are ultrasonic testing and magnetic flux leakage. Ultrasonic testing involves the use of highfrequency sound waves to measure pipe thickness, identifying corrosion on the outside or inside. Magnetic flux leakage relies on the creation of a strong magnetic field and identifying leakage of magnetic flux lines through the pipes, which indicates corrosion. Engineers can take this data and use corrosion growth rate models to predict the growth rate and integrity of the asset over time.

PREDICTIVE MAINTENANCE

All the data provided by these testing and monitoring technologies serve a purpose: preventing pipeline corrosion

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DATA-DRIVEN INSIGHTS

It is common for organisations to evaluate what they could have done better to prevent pipe corrosion from causing failure of the line, but they do not have to wait for the failure to achieve this goal. With the collection and processing of large quantities of data about the pipelines from inside and outside the organisation, engineering teams can gain datadriven insights. An integrated artificial intelligence system processes the data and reveals trends and histories of specific pipelines. The data can yield recommendations for further actions, such as increasing maintenance routines or installing a product from a chemical injection skid manufacturer. Preventing corrosion from causing pipeline failures is an operational, maintenance, and safety concern.

ABOUT THE AUTHOR Dauren Kazimbek is business development manager for SMARTCORR – a global leader in providing comprehensive solutions to protect asset integrity. SMARTCORR strives to help its customers achieve profitability, reliability and sustainability in the oil and gas industry. Kazimbek has 25 years of experience in the industry and focuses on business development, investment and management.

Maintenance crews put themselves at risk for exposure to hazardous substances by utilising outdated monitoring methods. They also risk operational interruptions through those methods. By implementing real-time corrosion monitoring, maintenance teams minimise the amount of time they spend inspecting pipelines while dramatically increasing the data available for predictive maintenance and early repairs.

For more information visit: www.smartcorrs.com

OPERATIONS & MAINTENANCE

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OPERATIONS & MAINTENANCE

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Q&A: OFFSHORE ASSET INTEGRITY

We caught up with Dinko Cudic, head of marketing and applications development at Henkel Adhesive Technologies to discuss offshore asset integrity, the challenges that keep operators awake at night and what decades of infrastructure protection and repair have taught us

rom FPSOs and offshore platforms to pipelines and refineries, energy infrastructure operates in some of the harshest environments on earth. Constant exposure to saltwater, changing temperatures, UV radiation and mechanical stress means operators are in a continual battle against degradation. As operators look to maximise value from existing assets while maintaining safety and reliability, asset integrity has become a bigger part of the conversation. We explore some of the key challenges facing operators today

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and how proven protection and repair technologies can help. Offshore assets operate in some of the harshest environments on the planet. What challenges do operators face today? Offshore assets have a hard life. Whether it’s a platform in the North Sea, an FPSO off the coast of South America or a refinery in the Middle East, the environment is constantly working against you. Saltwater, humidity, UV exposure, temperature fluctuations and mechanical stress all contribute to degradation over time.

Then there is the practical reality of maintaining these assets. Access can be difficult, shutdown windows are often limited and any maintenance activity needs to be carefully planned around ongoing operations. The challenge for operators is finding the right balance between reliability, safety and cost, while keeping critical infrastructure performing exactly as it should. Has the conversation around offshore integrity changed in recent years? Absolutely. Historically, many

OPERATIONS & MAINTENANCE

conversations focused on identifying damage and deciding how best to repair it. Today the industry is taking a much more proactive approach. Operators are asking different questions. How can we prevent degradation before it becomes a problem? How can we reduce future maintenance requirements? How can we maximise the value of assets already in service? Those questions are becoming increasingly important as companies look to optimise operational expenditure while ensuring long-term reliability. There is also a growing recognition that protecting and repairing infrastructure is more practical and sustainable than replacing it entirely. Clients are not looking for temporary fixes. They need solutions that can withstand the realities of the operating environment and continue performing long after the repair team has left site. What role do composite repair systems play in modern offshore operations? Composite repair technologies have changed the way many operators approach asset repair. The ability to restore compromised infrastructure without major replacement activities offers significant advantages, particularly offshore where access, logistics and downtime can all present challenges. One example involved an FPSO where deteriorated pipework required intervention to restore safe operation. Taking large sections of pipework out of service would have resulted in considerable disruption, so a composite repair solution using ThermoWrap MT from CSNRI was installed to restore integrity and return the asset to safe operation. What makes projects like this particularly valuable is not just the repair itself, but the ability to complete it efficiently, safely and while supporting continued operations. The fact that composite repairs can often be carried out without hot work requirements can help reduce risk to both personnel and production, while minimising operational disruption. We’ve seen similar challenges elsewhere. In the North Sea, an ageing pipeline system was experiencing

Splash-zone protection on the Petra platform demonstrates the importance of selecting proven corrosion prevention systems for long-term offshore asset integrity

corrosion-related issues that threatened long-term reliability. Rather than pursuing a costly replacement programme, an engineered composite repair solution was used to restore structural integrity and support continued service. These projects demonstrate how repair technologies are helping operators address real-world challenges while extending the useful life of critical infrastructure. Corrosion remains one of the industry’s biggest concerns. Why? Because corrosion never takes a day off. It’s easy to think about corrosion only when it becomes visible, but by

that point the process has often been developing for some time. Offshore environments create ideal conditions for corrosion to develop, particularly where moisture, oxygen and salt are present. Add continual exposure to UV radiation and the challenge becomes even greater, placing additional demands on coatings and protection systems designed to safeguard critical assets. The biggest change we have seen over the years is the industry’s approach to protection. Rather than waiting for degradation to become evident, operators increasingly want systems that prevent corrosion from developing in the first place. This is particularly important in areas

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OPERATIONS & MAINTENANCE

where corrosion can remain hidden for extended periods, such as under insulation. The right protection strategy can help reduce maintenance requirements, improve predictability and lower overall lifecycle costs. It’s all about staying ahead of the problem rather than constantly reacting to it. Are there particular areas of offshore infrastructure that demand special attention? Splash zones remain some of the most challenging environments anywhere in the oil and gas sector. These areas are constantly exposed to seawater, changing tides, abrasion, impact from vessels and debris, as well as salt exposure. They also experience continuous wetting and drying cycles. It’s a combination that accelerates deterioration and creates significant maintenance challenges. This is where selecting the right corrosion prevention system becomes particularly important. A recent example is the Petra platform in the Adriatic Sea, where corrosion protection from STOPAQ was applied to 36 platform legs supporting Italy’s new floating LNG terminal. Operating in submerged and splash-zone conditions, the project demonstrates the importance of selecting proven protection systems capable of delivering longterm performance in harsh offshore environments. The same challenges are not limited to offshore platforms. Jetties and terminals face many of the same conditions, with operators often battling corrosion on assets exposed to seawater and changing tidal conditions. In one jetty project, Following premature coating failure, a STOPAQ corrosion protection system was applied to provide long-term protection while allowing terminal operations to continue

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ThermoWrap MT can be applied easily in areas of limited access. It also conforms well to complex geometries

STOPAQ Wrappingband solutions were selected following premature coating failure, providing a practical long-term solution that could be installed while operations continued. Looking ahead, what should operators be thinking about? The biggest opportunity is taking a lifecycle view of infrastructure. Asset integrity should never be considered only when a defect is identified. The most successful operators look at the bigger picture, considering how corrosion prevention, inspection, maintenance and repair strategies work together throughout the life of an asset. Every asset has its own challenges. Success comes from understanding the operating environment, selecting technologies with proven track records and taking action before small issues become larger problems.

Whilst the challenges may change, the fundamentals remain the same. Operators need safe, reliable infrastructure that performs as expected, often in environments determined to do the opposite. Asset integrity is rarely about responding to a single issue. More often, it’s about making the right decisions long before a problem has the chance to develop. Whether protecting offshore platforms, restoring FPSOs, reinforcing pipelines or preventing corrosion in splash-zone environments, the objective remains the same: keeping critical energy infrastructure operating safely, efficiently and reliably for decades to come.

For more information visit: www.henkel.com

OPERATIONS & MAINTENANCE

Solutions such as Daily Thermetrics’ AIRCOM End Node demonstrate how multiple inputs can be consolidated into a single field device

THE PATH FORWARD How increasing low-cost process measurements is transforming asset reliability in oil and gas, according to Daily Thermetrics

ngineers have always understood a simple principle: we cannot manage what we cannot measure. For decades, preventative maintenance programmes across the oil and gas industry have relied on scheduled inspections, operator experience, fixed instrumentation and periodic condition assessments. While these approaches have improved reliability and safety, they share a common limitation. There simply have not been enough process measurements available across operating facilities to provide the

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visibility needed to identify every developing issue before it becomes a costly maintenance event.

DIGITALISATION IS CHANGING THE EQUATION

Much of the industry’s discussion around digital transformation focuses on artificial intelligence, cloud computing and predictive analytics. However, the foundation of digitalisation begins much closer to the process itself. Before software can generate meaningful insights, engineers need accurate, reliable and

abundant data. The ability to increase measurement density throughout an operating asset at a practical cost is what is truly transforming preventative maintenance. Historically, adding instrumentation has been expensive and complex. Every new measurement point required engineering design, process penetrations, field wiring, junction boxes, marshalling cabinets and control system integration. In many cases, installation also required plant outages. As a result, instrumentation was typically reserved for only the most critical areas of the process.

OPERATIONS & MAINTENANCE

The consequence was that large portions of valuable equipment operated with limited continuous visibility. Reliability teams were often forced to make maintenance decisions using incomplete information, identifying problems only after performance had already deteriorated. Wireless technology has helped remove some of these barriers, but early adoption often replicated existing instrumentation philosophies rather than rethinking them. In many facilities, a wired pressure transmitter simply became a wireless pressure transmitter, and a wired RTD became a wireless RTD. The copper disappeared, but the one-instrument, one-device approach remained. While installation costs fell, new challenges emerged. Networks became crowded with individual devices transmitting single measurements. Battery maintenance requirements increased, and assets became surrounded by isolated instruments providing limited operational context.

OmniTrace is an advanced, high-density temperature monitoring solution

A SYSTEMS-LEVEL APPROACH

Process measurements naturally exist in groups around critical equipment. Pumps, heat exchangers, reactors and compressors are not assessed using a single variable. Engineers require a combination of temperatures, pressures, vibration, flow conditions and equipment status indicators to understand asset health and process performance. Modern telemetry platforms are increasingly reflecting this reality. Rather than treating every measurement as a separate endpoint, multiple inputs can be consolidated into a single field device. Temperature sensors, pressure transmitters, 4-20mA instruments and discrete signals can all be integrated into a hazardous-area communication node, reducing infrastructure while creating a more complete picture of equipment performance. Solutions such as the Aircom End Node platform from Daily Thermetrics demonstrate this evolution. Multiple process variables can be collected at the asset level and transmitted through a single LoRaWAN communication path rather than numerous independent

wireless devices. This reduces installation complexity, minimises maintenance requirements, improves network efficiency and delivers richer operational data. More importantly, it enables engineers to evaluate equipment as an integrated system rather than a collection of isolated measurements. Consider a pump. A single bearing temperature reading may reveal very little on its own. However, when viewed alongside suction pressure, discharge pressure, motor load and casing temperatures, that same measurement becomes significantly more valuable. Context transforms data into actionable information. This principle applies throughout refining, petrochemical and upstream operations.

Temperature monitoring offers significant opportunities for preventative maintenance because thermal behaviour is often one of the earliest indicators of deteriorating asset condition. Changes in temperature can reveal refractory degradation, insulation failure, exchanger fouling, catalyst issues, flow restrictions and abnormal operating conditions long before production losses occur. Traditionally, however, collecting additional temperature measurements has often been difficult and expensive. Conventional instruments typically require thermowells and process penetrations, increasing both installation costs and potential process risks.

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OPERATIONS & MAINTENANCE

Engineers need accurate, reliable and abundant data to ensure smooth oil and gas operations

NON-INVASIVE TEMPERATURE MONITORING

Modern surface-mounted sensors such as the Daily Thermetrics OmniTrace and MagVSS technologies can be installed directly onto pipelines, vessels, reactors and storage tanks without breaching the process boundary. Installation is faster, costs are lower and measurements can be deployed in locations that were previously considered uneconomical. The result is a dramatic increase in measurement density. Instead of monitoring one or two points on a large asset, engineers can monitor dozens. Rather than relying on isolated readings, they can build detailed thermal profiles that reveal localised changes in equipment condition. For refractory-lined equipment, external temperature monitoring using Daily Thermetrics’ MagMesh system can identify developing hot spots and insulation failures before they become reliability concerns. On heat exchangers, multiple measurement points can help detect fouling and performance degradation, while on process piping, they can highlight flow abnormalities, restrictions and changing operating conditions. The value of these measurements increases further when integrated into broader digital maintenance systems. Continuous monitoring enables trend analysis rather than periodic inspection. Data can be transferred

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into historians, SCADA systems, asset management platforms and analytics applications, allowing maintenance teams to identify deviations from normal operating conditions and prioritise interventions based on actual equipment health. This represents a significant shift from traditional timebased maintenance towards conditionbased maintenance strategies. Ultimately, the future of preventative maintenance will not be defined by artificial intelligence alone, nor by simply replacing cables with wireless devices. It will be defined by the industry’s ability to deploy more measurements, in more locations, at lower cost. Digitalisation is fundamentally a measurement challenge. Advanced analytics cannot analyse data that does not exist, and predictive maintenance cannot succeed where instrumentation coverage is inadequate. Low-cost wireless communications, non-invasive sensing technologies and consolidated telemetry architectures are now removing many of the barriers that once limited instrumentation projects. As measurement density continues to increase, operators gain greater visibility into asset performance, identify developing problems earlier and make better-informed maintenance decisions, all without the capital expenditure traditionally associated with expanding instrumentation infrastructure.

MagVSS and other modern technologies can be installed directly onto pipelines, vessels, reactors and storage tanks without breaching the process boundary

For more information visit: www.dailyinst.com

OPERATIONS & MAINTENANCE

Rovex is designed to clean more than 90% of accessible tube surface area

CLEAN COVERAGE A remotely-operated robot is tackling fired heater fouling

ired heater fouling remains one of the largest contributors to lost thermal efficiency across refining and petrochemical operations. According to IGS, even a 1% loss in steam cracker efficiency can cost operators several million dollars annually, making effective convection section cleaning critical to plant performance. The use of robotics can lead to major efficiency gains for operators if used appropriately. Robotics are increasingly being used in oil gas to automate repetitive tasks that can take operators away from their intended exploration or production responsibilities. Inspection, monitoring, maintenance and repair, for example, are all processes that can benefit

The use of robotics can lead to major efficiency gains for operators if used appropriately

from the deployment of robots. One application that demonstrates the potential advantages of robotics is Rovex, a robotic cleaning technology for fired heater convection sections, launched by IGS TubeTech in July 2026. Rovex is a compact, remotely operated vehicle (ROV) designed to improve access to complex tube geometries and remove heavy fouling with precision. The system supports measurable improvements in efficiency, reliability and emissions reduction through the effective cleaning of stubborn deposits on furnaces and fired heaters. According to IGS, the fully remote technology enables consistent cleaning coverage reaching over 90% of the surface area. This is an

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OPERATIONS & MAINTENANCE

improvement compared to traditional water jetting or manual techniques, which usually access 20-30% of fouled surfaces. The technology’s remote application eliminates the need for confined-space entry, but operators can still view the space through highdefinition visual data that the robot captures during cleaning. “It provides a practical way for operators to address fouling safely, before it leads to lost revenue, while achieving consistent and measurable performance improvements,” says Eric Duvekot, VP Engineering at IGS. Robotic mobility, IGS’ lance technology and digital performance verification all support these improvements. A thermal performance evaluation before and after cleaning supports each Rovex deployment to quantify efficiency

losses and target cleaning activity. “Rovex represents the next stage in the evolution of our robotic cleaning technology,” says Duvekot. “We’ve built on years of successful field deployment with the TubeTech platform, incorporating customer feedback and continued engineering development to create a more capable system.”

IN THE FIELD

IGS developed Rovex through extensive in-house research and field deployment. Recent field applications have demonstrated the Rovex’ abilities. At Oman Methanol Company, for example, Rovex restored convection section performance, reducing stack temperature by 34°C and improving fuel efficiency by 1.8%, enabling a return to full production capacity

while reducing fuel consumption and associated emissions. Additional recent projects have demonstrated fuel efficiency improvements of up to 2.9%; stack temperature reductions of up to 60°C; annual carbon dioxide emissions reductions exceeding 1,600t; and payback periods of less than three months, depending on furnace design and operating conditions.

FUTURE OPPORTUNITY

The oil and gas industry is currently under significant cost pressures. Inefficiencies caused by fouling can lead to unnecessarily high energy costs and less production. As robotics find their place in the oil and gas industry, it is worth remembering that the smallest maintenance activities are an opportunity for efficiency.

ROVEX ADVANTAGES ACCORDING TO IGS

The technology’s remote application eliminates the need for confined-space entry According to IGS, Rovex can triple surface area access compared to traditional fouling removal methods

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• 90%+ fouling removed • 2-5% increase in thermal efficiency • Up to 15% reduction in carbon dioxide emissions • ROI within two months

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Henkel combines proven technologies, application expertise and long-term protection solutions to help extend asset life, reduce risk and improve reliability. From new construction and commissioning through to maintenance, rehabilitation and repair, we help operators protect critical assets throughout their lifecycle.

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OPERATIONS & MAINTENANCE

GOING GREEN Continuous emissions monitoring is the way forward for offshore oil and gas operations

hile many oil and gas companies are open to pursuing environmentally sound strategies, common obstacles are cost and the anticipated logistical difficulty of moving to new systems. However, options for the transition are becoming more available. Climate-tech company Daphne Technology’s PureMetrics continuous emissions monitoring system has been found suitable for the direct monitoring of selected greenhouse gas emissions from marine diesel engines onboard ships. PureMetrics can measure and report exhaust gas emissions in a way that enables tankers to observe and report their environmental impact. “Accurate emissions measurement is becoming increasingly important for shipowners and operators. Our assessment confirms that PureMetrics has a sound technical basis for directly monitoring and quantifying emissions from marine engines,” says Max Wu, lead specialist, Engine and Emissions Certification Services at Lloyd’s Register. Real-time data of emissions such as methane and carbon dioxide are available to view on a dashboard. Automated, direct reporting is possible to EU MRV and IMO DCS. Reports can be simplified and customised for individual company needs. Cloudbased infrastructure offers secure data storage and instant global access to data. PureMetrics helps to reduce operational costs by identifying inefficiencies and optimising performance. It does so while supporting carbon credit applications. The installation process of PureMetrics is also cost-effective, integrating easily with existing systems. Comprehensive, data-driven insights assist operators in making informed decisions while remaining compliant with strict international reporting standards.

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The customisable dashboard provides real-time emissions data and trends in a clean interface

NOW SUITABLE FOR TANKERS

The assessment, issued by Lloyd’s Register, was based on documentation and onboard demonstration testing. It includes an LR Design Appraisal of the PureMetrics system and its emissions calculation methodology. “The Design appraisal and Factual Statement provide independent validation of the system’s design and methodology, giving the industry greater confidence in the quality and consistency of the emissions data it handles,” says Wu.

Ivan Raleff, managing director Switzerland, Daphne Technology; Andy McKeran, chief growth officer, LR; and Kuldipak Pednekar, head of Marine & Offshore Operations, Daphne Technology

The appraisal confirmed that PureMetrics is designed to monitor carbon dioxide and methane, alongside carbon monoxide, nitrogen oxides (NO and NO2) and sulphur dioxide. The system is intended for use on marine diesel and dual-fuel engines. “Receiving the Lloyd’s Register Factual Statement and presenting it to shipowners and operators at Gastech 2026 marks another step in the independent validation of PureMetrics as a credible basis for direct emissions reporting,” says Daphne Technology SA Switzerland managing director, Ivan Raleff. “The appraisal confirms that the system’s design and methodology meet applicable requirements across a wider scope of greenhouse gases.” LR carried out the assessment against relevant IMO, EU MRV and NOx Technical Code documents. The Factual Statement also references IMO Resolution MEPC.416(84), the first dedicated IMO guidelines covering continuous emissions monitoring systems (CEMS) for marine diesel engines, adopted at IMO MEPC 84th session in 2026.

For more information visit: https://daphnetech.com

OPERATIONS & MAINTENANCE

WHERE THERE’S SMOKE…

A look at MCT Brattberg’s approach to specifying cable penetrations for hydrocarbon and jet fires A cable transit requires an individualised approach because carrying the right fire rating doesn’t automatically mean it is suitable

For oil and gas projects, selecting the seal requires a holistic approach, beginning with a documented project fire assessment

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cable transit can carry the right fire rating and still be unsuitable for the opening shown on the drawing. The difference may be the supporting structure, the cable diameter or a detail of the insulation. For oil and gas projects, selecting the seal means checking how the complete installation will perform under the fire exposure identified for that location. That work starts with the project fire assessment. It should establish the required barrier function and duration of protection, taking account of credible fire scenarios. A penetration beside pressurised process equipment may face different conditions from one serving an electrical room. The penetration specification needs to reflect those local conditions. The assessment should also identify which side of the division may be exposed. A-class and H-class ratings describe performance under different fire exposures. A-class testing uses the standard fire curve, while H-class testing applies a hydrocarbon curve with a more rapid temperature rise and higher test temperatures. The number attached to the classification identifies the insulation period. An

OPERATIONS & MAINTENANCE

Ensuring fire resistance requires different tools and approaches than other safety measures like gas and water tightness

A60 rating therefore cannot establish suitability for an H60 requirement.

EVALUATING RESISTANCE TO JET FIRES

Jet fires introduce a further consideration. An ignited release of pressurised hydrocarbon can direct a flame onto a local area of the division. Intense heating and mechanical action challenge exposed insulation and interfaces. Where this is a credible scenario, engineers need appropriate jet-fire evidence, including the test conditions and acceptance criteria. ISO 22899-1 provides a method for evaluating resistance to jet fires. Its results contribute to the fire assessment for the intended application. Jet-fire testing complements hydrocarbon fire resistance testing; it does not replace it. Where both exposures form part of the design basis, the supporting evidence needs to address both. The assessment must also follow the complete penetration through the structure. In a modular transit, the frame, sealing blocks and compression components work together. Their performance depends on the

surrounding division and the specified insulation. A material flammability classification, on its own, cannot establish the fire resistance of that assembly. Approval for a welded frame should not be assumed to cover a bolted installation. The published ABS design assessment for MCT Brattberg’s RGS system illustrates this relationship. One J120 arrangement uses a 300 mm back-to-back frame and specifies maximum marine cable and metallic pipe diameters of 110mm and 30mm respectively, with a defined insulation arrangement. Those dimensions belong to that configuration. They should not be transferred to another arrangement simply because it carries the same system name.

THE IMPORTANCE OF INSULATION

Insulation deserves particular attention during design coordination. Its thickness, extent and attachment must follow the approved detail. Space around the opening must accommodate that detail once cable trays, pipe supports and neighbouring services are installed. If the insulation cannot be fitted as specified, the

discrepancy needs resolving before the penetration is accepted. Consider a cable tray positioned close to a bulkhead. The transit may fit neatly into the available opening, yet the tray can obstruct access needed to complete the insulation. Moving the tray during design is straightforward compared with altering a finished installation. Reviewing the penetration in section, as well as in plan, helps reveal this type of conflict. Cables and metallic pipes also carry heat through a division. Their construction and dimensions therefore matter to the assessment, even when the opening is completely sealed. Substituting a different pipe material or increasing a cable diameter needs checking against the approval. Geometric fit alone does not demonstrate equivalent fire performance.

A HOLISTIC APPROACH Fire resistance must also be distinguished from gas and water tightness. A pressure test provides evidence about leakage under its stated conditions. It cannot demonstrate resistance to fire. Where

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OPERATIONS & MAINTENANCE

Substituting a different pipe material or increasing a cable diameter needs checking against the approval. Geometric fit alone does not demonstrate equivalent fire performance Having the right cable transit systems are critical to seal wall and deck openings and maintain safe operations

a barrier has several protective functions, the specification should identify the evidence required for each, including any requirement to withstand combined or sequential exposures. During installation, the approved drawing should be available alongside the manufacturer’s instructions. Checks should confirm the actual cable and pipe dimensions, correct components and completion of the compression procedure. Insulation should be inspected before adjacent work conceals it. Assigning responsibility for these checks prevents uncertainty between the structural, electrical and insulation contractors. The completed record should identify the penetration and connect its installed arrangement to the applicable approval. Photographs help show details that become difficult to inspect later. When cables are subsequently added or removed, that record provides a basis for checking the revised configuration and confirming that the specified protection has been restored. Changes

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Specialised equipment can help protect against many variables including supporting structure, the cable diameter or a detail of the insulation

in cable routing can also affect access to insulation around the opening. A useful final review is to place the approval drawing beside the installation drawing and account for every difference. Resolve deviations with the manufacturer and the relevant approving authority before

accepting the work. That gives the operator a documented basis for the barrier’s intended performance.

For more information visit: www.mctbrattberg.com

Sealing solutions for cable and pipe penetrations

PRODUCTION & PROCESSING

MAPPING IT OUT Performance-based mapping is changing fire and gas detector layouts across the Middle East. Micropack managing director Graham Duncan explains why Onshore farm tank, where each detector’s field of view is modelled against the plant geometry

he Middle East is building. Gas processing, LNG, petrochemicals, hydrogen and carbon capture projects are moving at a pace few other regions can match. At the same time, operators are extending the life of assets that have been producing for decades. Both create the same question. How do you know your fire and gas detection system will actually detect the hazard it was installed for? For a long time, the honest answer was that you didn’t. Detector layouts were typically produced by experienced engineers using judgement

Graham Duncan is a certified fire and gas practitioner with over 20 years of experience in the oil, gas and energy sectors

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and rule-of-thumb spacing. Sometimes that judgement was good. Sometimes it wasn’t. Either way, there was no objective way to demonstrate coverage, and no way to show a regulator or an insurer that the design would perform.

FROM JUDGEMENT TO EVIDENCE

Fire and gas mapping changes that. It is a performance-based assessment of detector coverage, carried out in a 3D model of the facility. For flame detection, the assessment is geographic. Each detector’s field of view is modelled against the plant geometry, accounting for obstructions such as vessels, pipe racks and structural steel. The output is a coverage map showing exactly which areas can see a fire of a defined size, and which cannot. For gas detection, the assessment is different. Gas clouds do not respect detector sightlines, so the analysis is volumetric or scenario-based, considering release points, ventilation

and the size of cloud the system must detect before it becomes a threat. The discipline now has a codified basis. BS 60080:2020 gives explicit guidance on the placement of flame and gas detectors, and ISA TR84.00.07 provides a framework for evaluating fire and gas system effectiveness. Together they move detector layout from an art to an engineering deliverable that can be verified, audited and handed over with the rest of the safety case.

WHY IT MATTERS MORE IN THE GULF

The Middle East presents specific challenges for optical flame detection. Intense sunlight, heat haze, dust and highly reflective surfaces all work against detection reliability. A detector that performs well in the North Sea will not necessarily behave the same way at a gas plant in the Empty Quarter in August. Radiant sources such as flare stacks and hot exhausts add further potential for false alarms.

PRODUCTION & PROCESSING

Currently, mapping is increasingly being written into the contract as a design deliverable

This is where mapping earns its keep. The study does not just position detectors. It forces early decisions about detection technology, fire size targets and alarm voting philosophy, all assessed against the real environment rather than a datasheet. A mapping study that assumes ideal conditions is not worth the paper it is printed on. There is an economic argument too, and it cuts both ways. Underdetection leaves hazards uncovered. Over-detection is the more common finding in practice. It is not unusual for a mapping study of an existing facility to show that coverage targets can be met with fewer, better-placed detectors than the original design assumed. Every detector removed saves capital cost, installation, cabling and a lifetime of maintenance and proof testing. On a large facility that adds up quickly.

BROWNFIELD AND NEWBUILD

The regional opportunity splits into two workstreams. On new projects,

mapping is increasingly written into the contract as a design deliverable, with coverage targets defined at FEED and verified before handover. Operators in the UAE and wider Gulf are adopting performance-based requirements in their own engineering standards, and EPC contractors are expected to demonstrate compliance rather than assert it. On existing assets, the driver is assurance. Many facilities in the region are running detection systems designed twenty or thirty years ago, before mapping existed as a discipline. A retrospective study answers a simple question for the asset owner: does the installed system meet a modern coverage standard? Where it does, that is now demonstrable. Where it does not, the gaps are identified and can be closed in a planned way rather than discovered after an incident.

BUILDING CAPACITY IN THE REGION

gas mapping is not software alone. The tools produce the coverage analysis, but the judgement about fire size, hazard grading and voting philosophy still sits with the engineer. As the Middle East localises more of its engineering capability, there is growing demand for structured training in fire and gas detection design, and for competency that can be assessed rather than assumed. That is the future being mapped out in the region. Detection designed against defined performance targets, verified in a model before a single detector is installed, and maintained as a living record through the life of the asset. It is a straightforward idea. Safety systems should be proven to work, not assumed to. The Middle East’s new generation of projects is well placed to build that in from day one.

For more information visit: www.micropacksafety.com

The final piece is people. Fire and

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PRODUCTION & PROCESSING

FAIL-SAFE ACTUATION Rotork’s actuation for tank and terminal operations

The S13 is certified with Systematic Capability SC-3

alve actuation plays a critical role in maintaining safe and reliable operations across tank storage facilities, terminals, pipelines and process plants. Beyond delivering the required torque or thrust, actuators must ensure that valves move to a safe position when required while remaining practical to install, commission, operate and maintain. In many tank and terminal applications, actuators form part of wider safety instrumented systems (SIS) and are required to operate in hazardous or exposed environments. At the same time, operators are seeking ways to reduce system complexity, improve maintainability and gain greater visibility into asset condition.

ELECTRO-HYDRAULIC ACTUATION

Electro-hydraulic fail-safe actuation offers a practical solution. By combining electric operation with hydraulic control and mechanical

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spring-return or accumulator-based fail-safe functionality, these actuators provide precise valve control during normal operation while ensuring movement to a predefined safe position when required. Fail-safe capability is particularly important for emergency shutdown (ESD), isolation, loading and unloading and product transfer duties. Depending on site requirements, actuators can be configured to failopen, fail-close, or remain in position following the loss of an ESD signal or power supply. This flexibility allows operators to align actuator behaviour with specific process safety strategies. Traditionally, electro-hydraulic systems have relied on external hydraulic power units, associated pipework and supporting infrastructure. While effective, these systems can increase installation costs, maintenance requirements and overall system complexity. Self-contained electro-hydraulic actuators eliminate the need for

central hydraulic power units by integrating the hydraulic system and fail-safe mechanism within a single package. For example, Rotork’s Skilmatic SI range combines a selfcontained electro-hydraulic control module with a spring-return scotch yoke drive, requiring only an electrical power supply. This approach can significantly simplify installation, reduce maintenance demands and minimise site footprint. The Skilmatic SI range is suitable for use in safety instrumented systems (SIS), with SI3 and SI4 actuators certified with Systematic Capability SC-3 and suitable for use in SIL 2 and SIL 3 systems. The actuators also accept various input signals as standard, including ESD and partial stroke testing (PST), thereby supporting safety-critical duties. PST is particularly useful in applications where valves remain in one position for extended periods but must operate on demand. PST allows operators to test part of the valve stroke

PRODUCTION & PROCESSING

The Skilmatic SI on a tank farm

without fully interrupting the process, helping demonstrate that the valve and actuator remain capable of movement. Actuators in these environments need to be robust enough to withstand these conditions while remaining accessible for operators. They are available

with hazardous area certification and ingress protection ratings up to IP66/68 (control modules) and IP66/67 (complete assembly). These designs can be specified for operating temperatures from -50 to +70°C, supporting use in a wide range of environmental conditions.

Modern asset management capabilities further enhance reliability. An onboard data logger captures and stores valve, actuator, and control-signal operation and status data, and can store up to 3,000 events. This data can be used to support diagnostics, trend analysis and asset management, helping operators review test history and valve performance over time. When combined with digital asset management platforms, this data enables conditionbased maintenance, helping operators identify potential issues before they lead to unplanned downtime. As tank farms and terminals continue to focus on safety, reliability, and operational efficiency, selfcontained fail-safe electro-hydraulic actuators offer a practical way to reduce complexity while maintaining the performance, safety, and diagnostic capabilities required for critical valve applications.

For more information visit: www.rotork.com

When trust matters most. We share the load. RUD solutions for the safe lifting and handling of loads in offshore and subsea operations.

wesharetheload.com

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PRODUCTION & PROCESSING

EVERY

CONNECTION

COUNTS

Meeting the demands of modern oil and gas lifting operations

n the oil and gas industry, a relatively small component can have a significant impact on a much larger operation. Lifting, pulling, securing, towing and subsea activities all depend on reliable connections between loads and equipment. When an operation takes place offshore, in a confined space or hundreds of metres below the surface, the requirements placed on these connections become even more demanding. The hardware required to support these operations is therefore remarkably diverse. From shackles and hooks to sockets, chain fittings and specialised subsea equipment, each application can bring its own combination of loads, dimensions, accessibility and environmental conditions. For engineers, selecting the right component is more than checking if a product is suitable for

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With a slimmer screw bolt the slim shackle can be used in confined spaces

a particular application. Geometry, handling, safety, durability and availability can all influence whether a product is suitable for a particular application.

WHEN AVAILABILITY BECOMES PART OF THE EQUATION

In the oil and gas industry, time is rarely a neutral factor. Offshore projects involve vessels, crews, specialised equipment and carefully planned operations. If a relatively small component is unavailable, a much larger operation can potentially be delayed. The cost of downtime can quickly exceed the value of the component itself.

This makes product availability an important consideration when specifying lifting and rigging equipment. Maintaining availability across a broad product portfolio presents a considerable logistical challenge. A supplier needs to stock not only commonly used lifting components, but also specialised products for demanding applications, including subsea operations and heavy lifting. Green Pin has therefore placed considerable emphasis on maintaining high stock levels across its entire product range and building a global distribution network. With more than 1000 distributors worldwide, products can be delivered virtually anywhere

PRODUCTION & PROCESSING

in the world within 72 hours. For an engineer or project team, this means that technical suitability does not have to be considered separately from practical availability. The right component also needs to be accessible when the operation requires it.

ENGINEERING AROUND REAL-WORLD CONSTRAINTS

Innovation in rigging and lifting does not always mean developing a completely new product category. Sometimes the most useful innovation comes from identifying a specific limitation in an established product and redesigning it around the way it is actually used. A good example is the newly developed Green Pin Bow Shackle SCP. A standard bow shackle with a slimmer screw bolt and cotter pin. The two components form a double-safety principle for this ‘slim shackle’. The screw bolt enables quick assembly and disassembly, while the cotter pin provides a second mechanical safeguard against unintended opening. The compact design of the slim shackle also addresses another practical challenge: restricted access. With a slimmer screw bolt that sits within the width of the shackle body, the design creates a clean and compact profile that is less likely to snag and easier to handle in confined spaces. The idea for the product came from Aleksandr Ometov, technical trainer at Green Pin, who initiated its development.

Offshore operations demand the right equipment

“The main driver behind this project was finding the sweet spot between speed and safety,” says Ometov. “A standard screw pin shackle is fast and simple because it consists of only two parts, but it does not provide secondary security. A safety bolt shackle offers that additional security, but handling the extra components can slow down the operation and increase the potential drop-object risk.” Reducing the number of separate

PRODUCT SPECIFICATIONS GREEN PIN BOW SHACKLE SCP • Material: Bow and pin, high tensile steel, Grade 6, quenched and tempered • Finish: Hot-dip galvanised; powder-coated pin

The Green Pin Bow Shackle SCP, The Slim Shackle

• WLL range: 4.75–9.5t • MBL: 6 × WLL • Temperature range: -40°C to +200°C • Certification: 2.1, 2.2, 3.1, MTCa, CE • Standard: EN 13889 and meets performance requirements of US Fed. Spec. RR-C-271 Type IVA Class 2, Grade A, from 2 t and upward these shackles comply with ASME B30.26

components has an additional practical benefit. There are fewer loose parts that can be dropped or lost during installation, removal or handling — particularly relevant when working offshore, at height or in hardto-reach areas. The Green Pin Bow Shackle SCP is suitable for general lifting, pulling and load securing operations and can be used for both inline and side loading applications. It is available with a working load limit from 4.75 to 9.5t, with a minimum breaking load of six times the WLL.

SMALL COMPONENTS, CRITICAL ROLE

The oil and gas industry will continue to demand a wide variety of lifting and rigging solutions. While the individual components may differ from one application to another, their role remains essentially the same: providing a reliable connection within a much larger operation. Green Pin may be only one small link in a much larger lifting project, but it is a link that cannot afford to fail. That is why the focus extends beyond producing lifting hardware. It is about understanding real-world challenges, developing solutions around those challenges and ensuring that those solutions are available to the industry when they matter most.

For more information visit: www.greenpin.com

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PRODUCTION & PROCESSING

GROWING TOGETHER Gastech 2026 brought together natural gas players from around the world, highlighting current industry trends and global needs

n September, 59,468 people from over 150 countries attended Gastech, the world’s largest exhibition and conference dedicated to natural gas, liquefied natural gas (LNG), hydrogen, lowcarbon solutions, and AI for energy. One company exhibiting at Gastech 2026 was ContiTech, a developer and manufacturer of rubber, plastic, metal and fabric products, systems and components. On display was ContiTech’s API 17K hose technology designed for offshore service, which offers fatigue resistance, pressure integrity and motion accommodation. By absorbing operational movements between the FSRU and the jetty, the hoses reduce mechanical stress, simplify installation and enhance system reliability. “For LNG terminal developers, the priority is a gas transfer connection they can rely on in demanding marine conditions, without adding complexity to installation or longterm maintenance. That is the problem our API 17K certified hose solutions are built to solve,” said Scott Weston, head of energy fluids, ContiTech IAPAC. The API 17K hose technology supports faster and safer project execution and long-term operational performance for LNG terminal developers and operators across the Asia Pacific region. As floating storage and regasification units accelerate natural gas import projects in the region, safe and reliable gas transfer connections are increasingly crucial components for smooth operations.

A GLOBAL INDUSTRY

Gastech stretched its influence beyond Southeast Asia with a ministerial session titled, Africa Takes Power: Control, Sovereignty and Growth. The session explored how African nations can convert energy potential into industrial growth, greater energy access and long-term economic value. Hon. Yeukai Simbanegavi, Deputy Minister for Energy & Power

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Major agreements spanning LNG supply, power generation, upstream development, petrochemicals and shipping show how decisions made at Gastech 2026 are translating directly into new supply, infrastructure and industrial capacity

API 17K solution for natural gas transformation

Development, Zimbabwe, stated: ”Over the years, we have been relying on imports from other nations, but recently we have discovered oil in the northern part of Zimbabwe. We are working with investors, but we still need more people to come and work with us. We need to upgrade our national grid so that investors can have the correct infrastructure in place to be able to market their investments.” Speakers in the session considered the partnerships and investment models needed to ensure that resource development strengthens national resilience while opening new supply opportunities for international markets.

COMMERCIAL OPPORTUNITIES AT GASTECH

By the end of day three, memoranda of understanding, supply agreements

and investment commitments with a combined estimated value of US$40 billion were announced or advanced in Bangkok. The agreements announced and progressed during Gastech 2026 demonstrate the event’s unique ability to turn strategic dialogue into commercial action. Producers, buyers, governments, investors, technology leaders and infrastructure providers are using the event to secure long-term supply, expand power-generation capacity, unlock new resources, strengthen shipping capability and build the infrastructure projects required to meet rising global demand.

For more information visit: www.gastechevent.com

PRODUCTION & PROCESSING

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PRODUCTION & PROCESSING

BESS can deliver fast active-power response, while improving site energy flexibility

THE HIDDEN CHALLENGE Why synchronous condensers and BESS must work together in weak-grid operations, reports WEG

lectrification is reshaping oil and gas site power systems. As fuel-driven equipment is replaced and renewable generation increases, local networks must remain stable under changing electrical conditions. This is increasingly important as the International Energy Agency (IEA) estimates oil and gas supply operations account for nearly 15% of global energy-related greenhouse gas emissions. Here, Mark Newman, business development manager for Energy Transition, Industrial Decarbonisation and Grid Stability at WEG, explains why synchronous condensers and BESS should form part of decarbonisation plans. As operators retire local gas-turbine generation and rely more on converter-

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connected assets, site networks can exhibit weak-grid characteristics. Reduced fault levels and lower system inertia mean the issue is not only energy availability, but whether the local network can remain stable as operating conditions change. According to the IEA, the production, transport and processing of oil and gas generated 5.1 billion tonnes of CO2-equivalent emissions in 2022, just under 15% of global energyrelated greenhouse gas emissions.1 The agency also says more than 80 million kilometres of power lines will need to be added or refurbished by 2040 to meet national climate and energy goals, a scale equivalent to the entire existing global grid. Higher use of inverter-based resources changes the way a network

responds to faults. Renewable generation and battery energy storage systems are essential to decarbonisation, but they do not behave like traditional rotating machines. Conventional generators naturally provide physical inertia. They can also support fault levels and help stabilise voltage during disturbances. A WEG Battery Energy Storage System (BESS) can deliver fast activepower response, while improving site energy flexibility. Advanced grid-forming BESS can also provide stability functions such as synthetic inertia and controlled fault-current contribution. However, grid-forming converters do not inherently replicate the physical inertia or natural fault-current response of a rotating

PRODUCTION & PROCESSING

WEG’s synchronous condenser solutions are designed around system requirements

synchronous machine. That is why WEG Synchronous Condensers have an important role where sites need a stronger electrical foundation for reliable operation. A synchronous condenser, or SynCon, is a rotating electrical machine connected to the grid without driving a mechanical load. It provides real inertia from rotating mass. Unlike synthetic inertia, which is delivered through control algorithms, the kinetic energy stored in a synchronous condenser rotor is available instantaneously. A synchronous condenser can also strengthen fault levels and help anchor the local voltage reference. Higher fault current levels can improve protection system performance and support large

motor starting duties. For operators, insufficient system strength can be measured in nuisance trips and production losses caused by failed motor starts. When equipped with a flywheel, a WEG flywheel-assisted Synchronous Condenser can store more kinetic energy, improving frequency stability further. WEG’s work with Empresa de Eletricidade da Madeira (EEM) provides a transferable example. Madeira is an isolated island grid with no synchronous interconnection. In 2025, the island had a renewable share of 37.4%, while instantaneous renewable penetration could reach 70% during off-peak hours. The grid also showed stability challenges, including low short-circuit current and frequency stability limits.

EEM’s response combined storage with synchronous support. Existing hydro units were adapted to operate in synchronous condenser mode, BESS capacity was introduced at strategic nodes and a dedicated flywheel-assisted SynCon was installed at Caniçal. Although industrial electrification projects differ from island power systems, both can experience low fault levels, limited inertia and high penetrations of converter-connected generation. The important step is to identify the binding constraint before choosing the asset. If the issue is energy shifting, BESS may be the priority. If the site also needs stronger fault levels or a firmer voltage reference, a SynCon may be required alongside storage.

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PRODUCTION & PROCESSING

WEG’s synchronous condenser solutions are designed around system requirements, not machine convention. In Madeira, the design was shaped by fault-current contribution and inertia, with reliability through grid disturbances built into the specification. The system used a lowvoltage variable speed drive (VSD) and pony motor starting arrangement to ramp the machine to nearsynchronous speed before connection, avoiding the inrush current that direct-on-line starting could create in a weak system. Commissioning is equally important. Weak-grid projects cannot be treated as standard handovers, because voltage and frequency can fluctuate continuously. On Madeira, synchronisation logic and drive firmware had to be tuned against real operating behaviour. For oil and gas assets, unstable power systems can be costly and difficult to restart. As the sector decarbonises, the priority is a resilient electrical architecture that allows cleaner generation and storage to operate without compromising uptime. WEG can support that approach with SynCon and BESS solutions, while its motors and drives, supported by automation expertise, help operators improve efficiency at the point of use. Electrification will continue to reshape oil and gas power systems, but the transition will only succeed if stability is designed into the network from the beginning. For remote or weak-grid sites, synchronous condensers can provide the physical foundation that allows lower-carbon technologies to operate reliably.

Oil and gas site power systems are changing because of electrification

[References] 1 Emissions from Oil and Gas Operations in Net Zero Transitions – Analysis - IEA

For more information visit: www.weg.net

A synchronous condenser can strengthen fault levels and help anchor the local voltage reference

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PRODUCTION & PROCESSING

A FRESH APPROACH A look at Babcock’s ecoAPEX, which could improve reliquefaction efficiency without adding complexity

s the oil and gas industry increasingly focuses on efficiency, companies are finding ways to improve efficiency while minimising technological complexity. British engineering company Babcock LGE, for example, recently launched ecoAPEX, an LR-approved integrated cargo handling technology. The technology is designed to improve the efficiency of onboard reliquefaction and gas fuel systems for liquified gas carriers. “As the industry continues to focus on efficiency, there is growing recognition that significant gains can be achieved by improving the performance of onboard systems as well as through fuel and propulsion developments,” says Andy McKeran, chief growth officer, Lloyd’s Register.

EFFICIENT HANDLING

According to the company, ecoAPEX could improve reliquefaction efficiency by up to 33%, cut reliquefaction energy consumption by about 25% and reduce loading and cooldown times by 14%. These numbers could help to deliver lower operating costs, lower emissions and improved operations. “By viewing the vessel as a connected whole, we unlock efficiencies from energy already available onboard,” says Babcock managing director Neale Campbell. By nature, dual-fuel gas carriers use a lot of energy, both to cool boil-off

Efficiency of onboard reliquefaction and gas fuel systems is becoming increasingly vital to gas carriers

Andy McKeran, chief growth oofficer, LR (left) presents the AiP to Neale Campbell, managing director of Babcock LGE at Gastech 2026

gas back to liquid and heat fuel to required temperatures. ecoAPEX takes a different approach. The system is designed to integrate both processes by using energy already available onboard. The technology connects the processes for cooling

boil-off gas through reliquefaction and heating gas for engine consumption. It does so without the need for additional rotating technology. “On dual-fuel gas carriers, ecoAPEX enables two processes that traditionally operate separately to integrate effectively, reducing cargo handling energy demand without adding equipment, complexity, or operational burden,” says Campbell. By recovering value from energy already onboard, the system offers a new approach to improving cargo handling efficiency without increasing system complexity.

For more information visit: www.babcockinternational.com

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HEALTH & SAFETY

– FROM THE INDUSTRY –

ELIOT SIZELAND Eliot Sizeland, Fire & Gas Detection Technologies, Inc. vice president of business development, shares valuable insights from his career in fire and gas detection solutions WHAT IS YOUR ROLE WITHIN FIRE & GAS DETECTION TECHNOLOGIES, INC. AND HOW LONG HAVE YOU BEEN WITH THE COMPANY?

I have been with FGD for nearly six and a half years. The team is amazing, and it is a genuine pleasure to work with such talented individuals. My job title is vice president of business development. I work closely with distribution partners, supporting their efforts to provide the right fire and gas detection solutions to end users. My role covers technical support, sales, training and helping our partners understand both the capabilities of our products and how best to apply them. I am normally called upon when an application is particularly challenging. I also spend a lot of time looking for new opportunities to improve the customer experience with our products, whether that is through new technology, better tools, improved training or simply making our products easier to select, install and use.

where a release is rapidly diluted or carried away from the detector. Flame detectors may have to deal with obstructions, reflections, hot surfaces, exhausts or other sources of radiation that can affect performance and cause false alarms. Another challenge is the tendency for projects to focus too heavily on capital cost. The lowest-cost detector or system is not necessarily the lowestcost solution over its operating life. False alarms, unnecessary shutdowns, repeated maintenance visits, difficult commissioning and poor diagnostics can all create significant operational costs. I would like to see more projects consider total cost of ownership and the operational consequences of detector selection, rather than simply the initial purchase price. I also think we need to keep improving the way we apply standards and approvals. Standards give us an essential common baseline, but an approval certificate cannot reproduce every environment a detector will encounter. We need to combine standards with good application engineering, realistic testing and an understanding of how the detector will behave on the plant.

WHAT ARE THE BIGGEST CHALLENGES WHAT DEVELOPMENT FACING THE INDUSTRY? HAVE YOU BEEN MOST PROUD OF One of the biggest challenges is WORKING ON? making sure that detection systems are designed around the actual hazard and the real operating environment, rather than simply selecting a detector from a datasheet. Fire and gas detectors are often expected to operate in very difficult conditions. Gas detectors may be installed in highly ventilated areas

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One development I am particularly proud of is our work on flame detection in environments where engine exhaust can create false alarm challenges due to the emission of hot carbon dioxide (CO2). With offshore operations, helicopters are used extensively to transport

personnel to and from shore, and rotor downwash can drive hot engine exhaust across the helideck and into the field of view of flame detectors. The detector must distinguish between a genuine hydrocarbon fire and the exhaust downwash associated with helicopter landing or taking off from a platform. FlameSpec CO2L was developed to specifically target this challenge. What makes me proud of this development is that it addresses a real operational problem rather than simply improving a datasheet specification. A detector that false alarms every time an aircraft starts its engines or a helicopter lands is not providing an effective safety solution, regardless of how well it performs in a laboratory test.

WHAT CHANGES HAVE YOU SEEN IN DETECTION TECHNOLOGIES SINCE YOU JOINED THE COMPANY?

The biggest change I have seen is the amount of intelligence now being built into detection products. Traditionally, a detector was largely expected to provide an alarm output. Today, we can extract far more information about what the detector is actually seeing and what was happening before, during and after an event. That is particularly important when investigating false alarms, because it gives us the opportunity to understand the cause rather than simply resetting the detector and waiting to see if it happens again. Video has also become much more important. Combining optical flame detection with high-definition video

HEALTH & SAFETY

Heads turn to Eliot Sizeland when a project is particularly challenging

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HEALTH & SAFETY

allows an operator to see what is happening in the detector’s field of view and provides valuable evidence when an alarm is investigated. We are also now seeing video analytics used alongside traditional flame detection so that two independent detection mechanisms can work together. Diagnostics and communications have improved significantly as well. Detectors can provide more detailed status information, record event data and make that information easier to access remotely. This is changing the way we commission, maintain and troubleshoot detection systems. For me, the most important development is not simply that detectors are becoming more sophisticated. It is that we are gaining a much better understanding of why a detector alarmed, what it was seeing at the time and whether changes can be made to prevent the same problem occurring again. That has the potential to improve both safety and operational reliability.

WHAT LESSONS HAVE YOU LEARNED DURING YOUR TIME IN THE INDUSTRY?

The biggest lesson I have learned is that there is rarely a single “best” detector. There is only the right detector for the particular hazard, environment and application. You have to understand what you are trying to detect, how the fire or gas release will behave, what could interfere with the detector and what happens operationally when an alarm is generated. Another important lesson is to listen. Some of the most valuable information comes from the people who operate and maintain these systems every day, and from our distribution partners who are close to the customer. When somebody tells you that a detector repeatedly alarms under a particular set of conditions, there is usually something to learn from it, regardless of its approval or standard compliance. Perhaps the most important lesson, though, is never to lose sight of why we do this. Fire and gas detection is ultimately about protecting people. After thirty years in the industry, that remains the reason I care about getting the engineering right.

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WHAT RECENT INNOVATIONS OR ADVANCEMENTS ARE YOU MOST EXCITED BY WITHIN FIRE AND GAS DETECTION TECHNOLOGIES?

I am most excited by the amount of information we can now obtain from a detector and how that information can be used to understand what really happened during an event. For many years, a detector essentially told us that it was either healthy, in fault or in alarm. Now, we can investigate false alarms in far greater forensic detail than was previously possible. Modern detectors can provide much more diagnostic information about what they were seeing at the time of an event. This gives us the opportunity to investigate alarms in far greater forensic detail than was previously possible. I am also very interested in the way different detection technologies can now work together. Combining conventional optical flame detection with video analytics, for example, allows two independent detection mechanisms to assess the same event. That can provide much greater confidence that an alarm represents a genuine fire rather than an environmental effect or false alarm source. The other area that excites me is making this information easier for customers to access and use. Better communications, remote diagnostics and improved configuration tools can make commissioning, maintenance and troubleshooting much more effective. For me, the real advancement is not simply making detectors faster or more sensitive. It is making them more intelligent, more transparent and better able to tell us why they made the decision they did.

IF YOU COULD CHANGE ONE ASPECT OF INDUSTRY STANDARDS OR REGULATIONS FOR FIRE AND GAS DETECTION, WHAT WOULD IT BE AND WHY? I would like to see an internationally recognised standard specifically addressing the performance of flame detectors against gas fires, and in

Detectors can take in more information than they used to

particular to hydrogen, methane, propane, butane and LPG. We already have established flame-detector standards, but when it comes to quoting detection performance against gas fires there is still far too much variation in the way manufacturers create and test those fires. That makes genuine comparison between products extremely difficult. A gas flame’s radiation and behaviour can be influenced by the burner design, fuel flow and pressure, flame dimensions, stability and flicker, and the way air is entrained into the flame. Different test arrangements can therefore produce materially different flame detector responses. What I would like to see is a reproducible test defining parameters such as fuel composition, burner geometry, fuel flow and pressure, flame dimensions, test environment, detector orientation, distance and response criteria. Ideally, the characteristics of the fire itself would also be sufficiently controlled or measured to demonstrate that a test performed in one laboratory is genuinely comparable with the same test performed elsewhere. That would give end users, consultants and manufacturers a meaningful basis for comparison. At present, impressive figures can be quoted for hydrogen or gaseous hydrocarbon detection, but when the underlying fire tests are different, comparing those figures can sometimes feel like putting a wet finger in the air. A proper standard would not necessarily make every detector perform the same. Quite the opposite: it would allow us to see the genuine differences between products because, for the first time, we would know they had been challenged by the same fire.

For more information visit: www.fg-detection.com

PRODUCTION & PROCESSING

Always one step ahead!

ISM_MA0343_260812

Discover our innovative mobile devices for ATEX/IECEx/NEC500 with the most advanced technology.

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HEALTH & SAFETY

SMALL ACCESSORIES, BIG IMPACT Getting the most out of Ex-certified devices, by i.safe Mobile

n hazardous area operations, the right device is only half the story. What turns an intrinsically safe smartphone, tablet, or radio into a genuinely productive daily tool is often the accessory that comes with it. i.safe Mobile offers a comprehensive accessory portfolio, developed alongside its Ex-certified device range, so field teams in oil and gas can charge faster, carry safer, and extend functionality without ever leaving the boundaries of ATEX and IECEx compliance.

KEEPING DEVICES POWERED, EVEN IN REMOTE LOCATIONS

Downtime caused by a dead battery is more than an inconvenience on a rig or in a processing plant, it’s a safety risk. That’s why charging solutions are engineered for real operational conditions. Desktop chargers provide fast, reliable singledevice charging at a workstation or control room, while the multi charger lets teams power up to six devices at once: ideal for shift changes, control rooms, or equipment lockers where multiple handsets need to be ready to go. It is available across a wide range of i.safe Mobile devices, including smartphones, tablet and radio series.

PROTECTION AND HANDS-FREE CARRYING

Devices used in demanding industrial environments need to survive drops, dust, chemicals, and constant handling, all without compromising certification. The Ex-approved belt clip keeps a device within easy reach while leaving both hands free for tools, valves, or climbing equipment. For teams who want an extra layer of protection, premium leather cases (available in black or high-visibility yellow) shield the device from scratches and impact while remaining fully Ex-certified. The tablet version adds an adjustable shoulder strap and a dedicated stylus holder, so operators can work hands-free and keep their stylus secure rather than searching for it. PanzerGlass foil for an extended

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Accessories can transform a device’s capability on site

protection of the display guards the touchscreen against scuffing and cracking without affecting touch sensitivity or glove operation: essential where screens face daily wear.

EXTENDING FUNCTIONALITY WHERE IT MATTERS

Beyond protection and power, accessories can transform a device’s capability on site. The IS-TH2ER.x barcode scanner turns the IS540.x into

Devices used in demanding industrial environments need to survive drops, dust, chemicals, and constant handling, all without compromising certification

a fast, reliable tool for asset tracking, inventory checks, and inspection workflows while scanning barcodes without interrupting other tasks. For teams relying on constant voice communication, Remote Speaker Microphones deliver clear, audio directly from the shoulder or lapel, keeping the primary device safely stowed while calls or radio traffic stay audible even in noisy environments. Headsets complete the communication chain, enabling clear two-way conversation in highnoise zones such as compressor stations or processing units, without requiring workers to remove PPE.

ONE ECOSYSTEM, BUILT FOR THE FIELD

What ties these accessories together is that none of them are afterthoughts — each is designed, tested, and certified specifically for i.safe Mobile’s Ex device range. For operators in oil and gas, that means fewer compromises: devices stay charged, protected, hands-free, and functionally extended, all while remaining fully compliant with the safety standards the industry depends on.

For more information visit: www.isafe-mobile.com

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HEALTH & SAFETY

AVOIDABLE

EXPLOSIONS

Crude oil, natural gas, and volatile chemicals can ignite rapidly. Credit: Chris LeBoutillier

A2E managing director David Ross breaks down key considerations for electrical/electronic equipment used in flammable atmospheres

afety is paramount in any industry involving hazardous atmospheres where there is the danger of explosion, such as the oil and gas sector. Explosive atmospheres can be created by flammable gases, mists, vapours or combustible dusts. If enough of the substance mixes with air, all that is needed to create an explosion is a source of ignition. Any electronic or electrical equipment used in a hazardous atmosphere could potentially provide this source of ignition, leading to an explosion which may result in loss of life, serious injuries and/or damage to infrastructure, along with the reputational damage and loss of confidence that such incidents create. It is vital therefore that the design of any equipment intended for use in a hazardous atmosphere is assessed to verify that ignition risks have been mitigated to an appropriate level depending on where the device is to be used. This will take place under the relevant Ex certification scheme for the country of use. For example, ATEX for the European market, IECEx which is recognised in many countries worldwide, or the Class/Division and Class/Zone systems which apply to the North American market.

EX MARKING CODES

Regardless of the certification scheme, there are some common factors which must be considered when determining the level of certification required for a particular device. Together these make up the Ex marking code for the device. Firstly, there is the ATEX equipment category, or Zone for IECEx and North American certifications, which defines the frequency of a hazardous atmosphere being present in a

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THE ATEX EQUIPMENT CATEGORY ATEX category 1 / Zone 0 (gas) or Zone 20 (dust) – Explosive atmosphere is continuously present. ATEX category 2 / Zone 1 (gas) or Zone 21 (dust) – Presence of explosive atmospheres is likely to occur in normal operation. ATEX category 3 / Zone 2 (gas) or Zone 22 (dust) – Explosive atmosphere is unlikely to occur in normal operation but may occur for short periods. particular site. This influences how likely it is for an ignition to occur due to a fault in the equipment and thus affects the level of requirements that must be met, for example whether dual or triple redundancy is required for Ex safety components. Secondly, all flammable gas and dust atmospheres are assigned to a particular Gas or Dust group, with the flammability of the substances involved determining which group the atmosphere belongs to. Higher groups apply more stringent technical requirements to the certification. Lastly there is the temperature classification, which defines the maximum temperature that any part of the device is allowed to reach in operation, and is selected to give a safe margin below the minimum ignition temperature of the explosive atmosphere.

HOW A2E CAN HELP

A2E is one of the UK’s leading experts

GAS AND DUST GROUPS Gas group I – e.g. Methane – for mining applications Gas group IIA – e.g. Propane – lowest flammability Gas group IIB – e.g. Ethylene – medium flammability Gas group IIC – e.g. Hydrogen – highest flammability Dust group IIIA – Combustible flyings Dust group IIIB – Nonconductive dust Dust group IIIC – Conductive dust in designing ATEX equipment. One of the most frequent concerns that clients have is how the requirement for Ex compliance will impact on the design and manufacture of a device. There is no single answer to this as each case is unique in terms of the level of certification required and the functional purpose and design of the device. Having handled many ATEX projects for the oil and gas and other sectors over the past two decades, A2E has built up a bank of expert knowledge in this field, and will be able to assist in choosing and implementing a suitable type of protection to achieve the required certification level whilst having the minimum possible effect on the technical specifications and cost of the device.

For more information visit: www.a2etech.com

The centrepiece of the Çanakkale suspension bridge. s at: Visit u 1230 EC #1 - ADIP X #29 - LIFTE

How to bridge two continents overseas with Green Pin® Super Shackles. The 1915 Çanakkale Bridge in Istanbul is the world’s longest suspension bridge being 3.7 km long, connecting Asia and Europe overseas. Yet, since the rapid growth

Project highlights Used sling shackles (400 t) and Green Pin Super® Shackles (G-5263) Longest suspension bridge in the world Total length of 3.7 km

of the social economy and tourism, the bridge needed an extension. For such a big and important project, Green Pin Super® Shackles were selected due to their weight, size, strength, and availability. The centrepiece of rigging in bridging two continents.

Scan the QR code to learn more about this project and product!

The suspension span is 2,023 meters long The bridge is designed to withstand earthquakes

SUBSEA TECHNOLOGY

A crucial safety advantage is offered by the increased WLL of the ACPTURNADO OCEANSTAR, including during dynamic load peaks in the splash zone. Image source: RUD

A DEFINING

MOMENT

IN LIFTING TECHNOLOGY

AT SEA

Lifting points are required for underwater lifting operations

A look at the first DNVcertified lifting point for subsea operations by RUD

he safety of subsea lifting operations in areas such as those around drilling rigs, offshore wind turbines, pipelines or construction and installation vessels always depends on the characteristics of the lifting points used. They must be highly resistant to corrosion and hydrogen embrittlement, and capable of withstanding extremely demanding lifting operations. This includes processes in the splash zone, where a load is lifted out of the water. Reduced buoyancy and water resistance, as well as wind and swell,

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Designed specifically for underwater operations, the RUD ACP-TURNADO OCEANSTAR is the first lifting point ever to be certified in accordance with DNV ST-0377 and ST0378 for subsea operations. Image source: RUD

SUBSEA TECHNOLOGY

The ACP-TURNADO OCEANSTAR from RUD has a spring mechanism to keep the lift bail vertical and delay flipping, thereby preventing shock loads. The lift bail always aligns in the direction of force instead. The striking golden colour of the lift bail ensures good visibility underwater, making handling easier and improving safety during diving and maintenance operations. Image source: RUD

often cause brief load peaks and unpredictable rotational movements, which must be safely absorbed by the lifting point technology. Therefore, for underwater lifting operations, lifting points are required. They must be made of suitable materials, offer sufficient WLL and be able to cope with changes in the load direction. Until now, anyone looking for such lifting points on the market could easily find them. In fact, the leading manufacturers have had solutions certified for maritime applications in their product ranges for decades, which are also used in subsea lifting operations. However, what was missing were lifting points with specific certification for subsea operations, which would demonstrate their suitability for use beneath the water’s surface. Consequently, such lifting operations could only be carried out using lifting points that did not have official subsea approval.

A NEW SOLUTION

The German lifting and lashing specialist RUD has developed a new lifting point that offers a solution. The ACP-TURNADO OCEANSTAR is the first lifting point ever to have explicit approval for subsea use, having been

certified in accordance with DNV ST-0377 and ST-0378. This officially qualifies it as a high-quality subsea lifting point. Compared with lifting points of a similar shape and design, it has a WLL that is up to 30% higher. This ensures a high level of safety, particularly during dynamic load peaks, such as those experienced in the splash zone. Users are also better protected against shock loads. Like all ACP-TURNADO lifting points from RUD, the ACP-TURNADO OCEANSTAR features a spring mechanism that stops the lift bail from staying upright at 90° and guarantees it always aligns with the force direction. The alignment with the force direction prevents loads from suddenly sagging if the lifting point or lift bail initially fails to follow movement, causing it to flip over with a delay or even break. This prevents high load peaks, which could result in a load collapse and pose a serious risk to people and equipment. The new lifting point also meets the highest standards in terms of materials. All its components are coated with an anti-corrosive zinc flake coating, guaranteeing salt spray resistance of at least 720 hours in

accordance with DIN EN ISO 9227. The required resistance to hydrogen embrittlement is ensured by reducing the maximum hardness to ≤ 38 HRC in all components and achieving notch bar impact values of at least 42J at -20°C. The golden colour of its lift bail also improves visibility underwater, making safe handling easier for divers or ROV operators. For maritime users, the ACPTURNADO OCEANSTAR from RUD is the first lifting point officially approved for subsea processes to significantly exceed industry standards at every technical level. It is available in thread sizes ranging from M8 to M30, with working load limits (WLL) from 0.5 to 8t. In practice, it can be effectively combined with products such as the RUD ROV-HOOK. The ROV-HOOK’s safety-optimised opening mechanism features silvercoloured twin triggers that provide effective protection against load loss. These two lifting components work together to set a new standard for underwater lifting at sea.

For more information visit: www.rud.com

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SUBSEA TECHNOLOGY

PACKING

POWER How to enable more autonomous and efficient subsea energy storage, according to SubCtech

he offshore energy sector is moving towards increasingly autonomous and electrified subsea infrastructure. Longer tiebacks, carbon capture and storage (CCS), subsea processing and the growing use of autonomous underwater vehicles (AUVs) are creating new demands for reliable power at the seabed. At the same time, operators are under pressure to reduce vessel time, installation complexity, operating costs and emissions. These requirements are changing the role of subsea battery systems. Rather than serving only as independent power sources for instruments, batteries are increasingly becoming part of larger subsea energy architectures. SubCtech has responded by expanding its PowerPacks battery platform and developing a modular Subsea Energy Storage System (ESS) for highcapacity offshore applications.

DESIGNING POWER FOR HARSH SUBSEA ENVIRONMENTS

A central engineering challenge is combining high energy density, long service life and reliability under harsh subsea conditions. Depending on the application, systems may need to operate for years with limited physical access while exposed to pressure, low temperatures, vibration, shock and corrosive environments. SubCtech’s lithium-ion PowerPacks are designed as configurable modules rather than a single battery type. Pressure-tolerant housings can be supplied in titanium (grades two or five) or super-duplex stainless steel for deployments down to 6,000m, while

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1MWh Battery Storage Skid lifted into the ocean for deployment

marine-grade aluminium housings are available for shallower applications up to approximately 1,000m. Different module diameters and electrical configurations allow the platform to be adapted to sensors, AUVs, ROVs and larger subsea installations. The batteries are controlled by SubCtech’s SmartBMS battery management system. It monitors operating parameters from individual cells through to complete module arrangements and provides protection against overvoltage, undervoltage, overcurrent, overheating, overcharging and short circuits. For larger systems, the control architecture also supports automated configuration, diagnostics and redundant operation. Qualification is particularly important because subsea battery systems must remain dependable when intervention is costly or impossible. The PowerPacks platform is tested for mechanical, thermal and electromagnetic loads and is designed with reference to established offshore and transport requirements including UN 38.3, API 17F/API 17Q, MIL-STD and DNV 2.7-3, depending on the system and application.

FROM BATTERY MODULES TO MEGAWATT-HOUR STORAGE

The latest step is a scalable subsea ESS for applications where power requirements exceed those of conventional standalone batteries. Its architecture combines two 1MWh battery storage skids with an integrated power skid containing AC/DC conversion equipment. A battery control module based on SubCtech’s NetDI technology

interfaces with the SmartBMS and manages the overall system. The modular architecture allows storage capacity to be expanded to as much as 6MWh. Redundancy is built into the system so that critical subsea consumers can continue operating if individual elements are unavailable. The system has been engineered for a design life of up to 25 years and, in its current configuration, for deployment at approximately 2,000m water depth, with deeper variants technically feasible. An important development milestone has been qualification of the ESS to API 17F and validation at Technology Readiness Level 7. The system has therefore progressed beyond laboratory testing and been demonstrated under conditions representative of an offshore operating environment. It has already been applied in the oil and gas sector, where a follow-on order provided an early indication of the practical value operators see in subsea energy storage.

SUPPORTING OIL & GAS, CCS AND AUTONOMOUS OPERATIONS The applications extend beyond conventional production. In CCS projects, local subsea energy storage can support monitoring, injection and control equipment while reducing dependence on long electrical connections to surface facilities. Similar concepts can be used for subsea compression, long tiebacks and offshore renewable energy systems, where local storage can buffer intermittent power. AUV operations provide another example: Larger vehicles increasingly

SUBSEA TECHNOLOGY

Underwater power-ecosystem to lower CAPEX and OPEX

require hundreds of kilowatt-hours of onboard energy, with some XXLAUV configurations exceeding 1MWh. Modular battery systems can be connected in series or parallel to achieve the required voltage, capacity and redundancy. Combined with seabed docking and charging stations, this enables longer autonomous missions without routine recovery to a vessel. This shift has wider operational implications. Vessel mobilisation is a major cost and emissions driver offshore. If subsea assets can operate longer, be monitored remotely and

recharge autonomously, vessel interventions can be reduced. Local energy storage may also replace or shorten certain umbilical or cable connections, particularly for remote infrastructure.

TOWARDS MORE AUTONOMOUS SUBSEA INFRASTRUCTURE The next phase of subsea electrification will therefore depend not only on greater battery capacity, but on integrating storage, power conversion, diagnostics and

communication into complete systems. For offshore operators, the objective is straightforward: reliable power where it is needed, with less surface infrastructure and fewer interventions. SubCtech’s development of modular PowerPacks and the subsea ESS reflects this transition from individual underwater batteries towards intelligent, scalable energy systems. As oil and gas, CCS and autonomous subsea operations increasingly converge around electrification, energy storage is becoming an enabling technology for the next generation of offshore infrastructure. “Our focus is on making subsea operations more autonomous, efficient and reliable,” says CEO Gunnar Tons. “By combining scalable battery systems with intelligent energy management, we can reduce surface dependency and support the next generation of offshore infrastructure.”

For more information visit: www.subctech.com

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SUBSEA TECHNOLOGY

COMPLEX, NOT COSTLY JB Valves explains why complex topside specifications need not carry bespoke pricing

opside high pressure valve procurement is under sustained cost pressure. At the same time, specifications are becoming more demanding: corrosion resistant materials, non standard connections and qualification evidence that goes beyond catalogue data. The conventional response is to treat anything outside the standard range as a bespoke development and to price it accordingly. That assumption is worth challenging.

WORKING DOWN, NOT UP

The starting point matters. Most topside valve designs evolve upward from general industrial practice, adding material upgrades and design changes as requirements become harder. A design developed for subsea service starts at the opposite end. Equipment installed on the seabed in the North Sea has to operate for years without intervention, in seawater, at pressure, with no practical means of maintenance. Material selection, sealing philosophy and qualification are set by that condition from the outset.

WHAT COUNTS AS EXOTIC

Brought topside, that starting point changes the economics. Specifications that represent an exotic departure for a general purpose manufacturer sit within normal practice for a subsea led design house. Corrosion resistant materials, high integrity sealing and documented qualification are routine rather than exceptional. Much of the engineering work has already been done, so meeting a complex specification becomes a matter of configuration rather than a development programme.

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Supporting mature assets means designing products that interface with equipment built decades ago by other manufacturers, often with incomplete records

THE LEGACY DISCIPLINE

Legacy compatibility reinforces the same habit. Supporting mature assets means designing products that interface with equipment built decades ago by other manufacturers, often with incomplete records. That work demands a core design flexible enough to absorb variation in connections, dimensions and materials without being redrawn each time. Applied to topside products, it allows a standard 20,000psi range to accommodate specification changes that would otherwise trigger a new build and a new price.

TESTING IN HOUSE

In house testing closes the gap on lead time. Burst testing to 65,000psi and qualification carried out on site removes dependence on third party facilities and their schedules. Evidence is generated to order rather than queued for, which matters when a complex specification is agreed late in a project.

ONE SUPPLIER, BOTH SCOPES

There is a supply chain argument alongside the engineering one. Operators and system builders procuring subsea equipment are frequently building the associated topside packages at the same time, and that scope is routinely split across separate suppliers for no better reason than habit. Customers who have procured ROV operated ball valves for subsea duty have also placed topside medium pressure needle valves with the same source, on straightforward cost grounds. The wider point is that complex does not have to mean costly. Where it does, it usually reflects where the design came from rather than anything inherent in the specification itself.

For more information visit: www.jbv.co.uk

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SUBSEA TECHNOLOGY

UNDER

PRESSURE Secc Oil & Gas managing director Steve Higgins delves into the value of QCDC technology in shallow and deep-water operations

igh pressure (HP) subsea workovers use a variety of tools and interfaces for routine and emergency situations when managing flow lines. Subsea HP couplings protect personnel, the environment and assets. Allowing subsea hoses and coil tubing to be coupled and decoupled safely. Whilst dynamic positioning (DP) technology has advanced, the need to protect subsea hydraulic downlines in the event of vessel drift-off or ROV error is still evident. For routine hydraulic interventions, the requirement for low-cost easy access to allow operators to access subsea assets, intervene and stimulate wells quickly and efficiently is a key consideration for the life of field.

KEEPING IT FLOWING.

Whilst nothing new, riserless light well intervention (RLWI) is slowly growing across the subsea intervention sphere — not just in keeping things flowing for mature functioning wells, but in pre-commissioning and the everpopular decommissioning. The key driver for RLWI is relatively low cost as compared to other Rig based intervention methods which use Risers. Ultra-light intervention systems open up the use of smaller vessels of opportunity for targeted interventions, further reducing the costs per campaign, where reliable QCDC technology is required. Shallow and deep-water operations have used quick connect disconnect (QCDC) technology worldwide for more than 20 years. This QCDC technology allows operators to plug and play by connecting and

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During controlled and emergency activations the ALTUM transitions from the open to the isolated state, simultaneously closing the flexible downline and fixed receptacle, before releasing

disconnecting hydraulic lines with minimal effort, with zero ingress and zero spill respectively, whilst offering a robust, no-frills emergency release point — one that works passively by hose tension or with a hydraulic override. Whilst most current applications have evolved with 10,000psi technology, deeper wells require the next level for reliable hydraulic intervention at 15,000psi.

FIELD-DRIVEN GAINS

The technology has matured over the last two decades through rigorous research and development testing, proven field history and operator feedback, with design iterations worked through alongside operators. This type of QCDC technology allows operations to get going quickly and safely following an emergency quick disconnect (EQD) incident.

SUBSEA TECHNOLOGY

PROVIDING MORE PRESSURE

QCDC technology has matured over the years

The patented ALTUM QCDC introduces 15,000psi capability, driven by demand in the Gulf of Mexico for ultra deep-water intervention at 10,000ft. Evolved from the Hot Make Hot Break QCDC, it allows operations to reconnect and continue without being pulled to surface. Manufacturing and performance features brought the design to a high level of performance and reliability, but there was more to solve for operators. The challenge? Stepping from 10,000psi to 15,000psi breakaway technology. Flexible downlines currently use midline weak links at 15,000psi. These sit between the hoses and act as a cruder “safety fuse”, which must be recovered and reset after activation. The ALTUM doesn’t. During controlled and emergency activations the ALTUM transitions from the open to the isolated state, simultaneously closing the flexible downline and fixed receptacle,

before releasing. This transition during an activation sees internal hydrostatic pressures creating high loads on the frame system of up to 87t, four times as much as the 10,000psi predecessor. The ALTUM masks these loads with pressure balanced seals and retention frame technology allowing the connector to isolate and release with zero external thrust. This exponential increase in transitional loads created a significant challenge for the engineering team and for the direction of the coupling, which needed to stay within a feasible weight and size envelope whilst meeting the full criteria. Work is under way with Tier 1 OEMs and service operators to integrate the ALTUM into a range of subsea systems.

For more information visit: https://secc-oilandgas.com

Minimise Risk, Maximise Uptime, DRIVE EFFICIENCY Subsea, Topside & Hybrid Valve Solutions J B Valves Ltd Majestic House, 29 Green Street, Huddersfield, West Yorkshire, HD1 5DQ, United Kingdom www.jbv.co.uk - enquiries@jbv.co.uk - Tel: +44 1484 509 888 - Registered in England No. 8994615

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SKILLS ZONE

CERTIFIED SESSIONS With Nigeria’s oil and gas sector undergoing a major surge, training is more important than ever

he Nigerian Content Developing and Monitoring Board (NCDMB) recently launched the Nigerian Content Trainers Registration Certificate (NCTRC) to strengthen local skills and promote professional standards within Nigeria’s oil and gas industry. The NCTRC is a digital verification and certification platform developed by the NCDMB to assess, inspect, verify, and rate training service providers operating within the Nigerian oil and gas industry. The initiative officially launched in late July. During its initial unveiling, executive secretary of NCDMB, Engr. Felix Omatsola Ogbe, represented by the general manager, Infrastructure and Capacity Building Directorate, Barr Sheba Olugbenga, commented on the need for a clear framework, stating: “The constantly changing services and requirements in the oil and gas industry and its linkage sectors, driven by technological advancements and smart innovations, have created the need for strategic and sustainable in-country capacity development and standardisation.” The introduction of the NCTRC aims to strengthen confidence in training service providers by ensuring that only organisations with the requisite facilities, personnel, and technical capacity are certified to deliver training within the Nigerian oil and gas industry. The initiative will also improve the quality, credibility, and standardisation of industry training programmes while supporting the development of a competent Nigerian workforce. The Regulation mandates that the Board establish a verification process for routine inspections, assessments, and ratings of training programmes, facilities, service delivery and performance. It also requires the Board to verify all information on training provided by operators and training providers on the NOGIC-JQS portal. Training service providers seeking

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The NCTRC will provide a transparent and standardised framework for evaluating oil and gas industry training providers

THE NCTRC CERTIFICATION COVERS 11 AREAS OF TRAINING SPECIALISATION • Health, safety and environment The NCTRC was unveiled during a sensitisation workshop held with members of the Oil and Gas Trainers Association of Nigeria

• Engineering and quality assurance • Petroleum and geosciences • Drilling, production operations and oil and gas processing • Facilities design and construction • Project management • Supply chain management • Asset management and maintenance • Information and communication technology

The young Nigerian graduates will spend 12 months in a programme teaching both hard and soft skills required in the oil and gas industry

certification will be assessed against criteria including training facilities, qualified instructors, relevant accreditations, equipment, previous training experience, and on-the-job training capability. Approved organisations will be classified into five categories based on their demonstrated capacity and capability, while successful certificates will remain valid for two years. According to the NCDMB, the certification programme is expected to contribute significantly to the development of a highly skilled workforce capable of meeting the evolving needs of industry operators and stakeholders.

A PRACTICAL APPLICATION

The verification of training services comes at a time when oil and gas training programmes are expanding significantly in Nigeria. In September 2026 for example, a year-long drilling

• Entrepreneurship, soft skills and oil and gas business • Maritime, nautical studies and offshore logistics

field-readiness programme began, preparing 38 young engineering and geosciences graduates for the oil and gas industry. The programme, delivered by the Board in partnership with Oando Energy Resources Nigeria Limited and their training partners, is structured into six months of classroom instruction and six months of on-thejob training. The programme covers basic drilling engineering operations, well planning and design, measurement while drilling (MWD), logging while drilling (LWD), drilling rigs operation and well logs data analytics, theoretical/ practical training. It also covers soft skills including entrepreneurship, business management and computer competency.

For more information visit: https://nogicjqs.gov.ng

WHERE ENERGY OPPORTUNITY TAKES SHAPE

Energy is entering a new era.

ADIPEC in numbers:

Rising demand, new technologies and intensifying competition are reshaping global energy markets – creating unprecedented opportunities to expand supply, attract investment and strengthen economic competitiveness. From 2–5 November in Abu Dhabi, ADIPEC 2026 brings together leaders, capital and capability to turn opportunity into action – advancing the partnerships, projects and technologies that will shape how energy is produced, traded and delivered.

JOIN THE GLOBAL ENERGY COMMUNITY

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TECHNIQUE

YELLOW

SKILLS ZONE

SPECIALIST SKILLS

How government funding is providing oil and gas workers with resources to tailor their technical careers and brace for uncertainty The Port of Cromarty Firth in Scotland supports central and northern North Sea decommissioning projects. Credit: Ben Wicks

orth Sea oil and gas production is in natural decline, with a 75% reduction in production occurring between 1999 and 2024.1 Data from Offshore Energies UK shows that over 70,000 jobs were lost in the North Sea oil and gas sector between 2016 and 2023.2 In late 2025, the UK government released the North Sea Future Plan, which supports the management of existing oil and gas fields for the entirety of their lifespans, as well as new investment in oil and gas production through Transitional Energy Certificates. The plan announced last year also intended to establish the North Sea Jobs Service, a national employment programme offering tailored support for the current workforce in industries such as oil and gas.

INVESTING IN THE FUTURE

In late June 2026, the UK and Scottish governments expanded upon its North Sea Future Plan by arranging a £6m investment to provide specialist training support for oil and gas workers living in Scotland. The aim is to help oil and gas workers use their specialist skills to move into

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new growing industries such as clean energy and advanced manufacturing. “The workforce that has driven Scotland’s oil and gas industry for generations is one of the most skilled and experienced in the world and it is vital that their expertise is preserved in the North East, and beyond,” says Scottish government energy minister Stephen Gethins. Robert Gordon University’s UK Offshore Energy Workforce Transferability Review found that over 90% of the UK’s oil and gas workforce have a medium to high skills transferability score and are well positioned to work in adjacent energy sectors.3 Eligible oil and gas workers in Scotland can now submit applications for the scheme. Successful applicants will receive careers advice and funding towards training courses for skilled and in-demand roles such as those in welding, electrical engineering and construction. The investment plan comes during a time when Andy Burnham, new UK prime minister, is facing intense scrutiny as he decides whether to greenlight new North Sea drilling. Given the uncertain future of oil and gas extraction in the North Sea, having a scheme to support skilled oil

and gas workers is crucial. “The skills and expertise of Scotland’s oil and gas workforce are in demand across a number of growing sectors,” says Scotland chair of skills development Frank Mitchell. “SDS advisers can help workers in the oil and gas industry to reskill and upskill for careers in growing sectors to help them build on their experience and ultimately transition into new roles.” The expanded investment follows a pilot scheme in Aberdeen and Aberdeenshire which helped over 400 North Sea workers retrain for roles in Scotland’s energy transition. “The North Sea’s workers and communities have helped power our country and our world for decades,” says UK foreign secretary Ed Miliband. “This is our plan to ensure they continue to do so for many decades to come.” [REFERENCES] 1 https://questions-statements.parliament.uk/ written-questions/detail/2026-03-20/122610 2 https://committees.parliament.uk/ writtenevidence/164293/html/ 3 https://www.rgueti.com/wp-content/uploads/ 2021/05/workforce-transferability-report.pdf

For more information visit: www.transitiontrainingfund.scot/

JOIN US

Cross-market focus: connect with leaders across oil & gas, offshore wind, maritime, CCS, hydrogen & renewables. Networking: meet peers, partners & industry experts.

Conference program: sessions on security, clean tech, circularity & renewable solutions. Innovators’ Area: dedicated space for startups & emerging solutions.

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SHOW PREVIEW

FACING THE CRUCIAL

CONVERSATIONS

mid a significant period of geopolitical volatility, the return of ADIPEC for its 2026 edition is both a surprise and a comfort to oil and gas industry players. Vulnerable chokepoints, attacks on infrastructure and economic uncertainty have rattled the sector, leaving more questions than answers. To address the conflict and its pivotal impact, ADIPEC’s Strategic Conference has been redesigned around the forces reshaping global energy, from rising demand and energy security to infrastructure, investment, AI, industrial execution and workforce capability.

WHAT IS NEW?

New Strategic Conference programmes include Energy Security & Resilience; Policy, Regulation & Governance; Upstream; Clean Power, Molecules & Carbon Management; Grids, Infrastructure & Industrial Execution; and Workforce & Skills. Existing programmes have also been updated to reflect the priorities shaping energy’s next phase, including AI, Digital & Technology Innovation

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SHOW PREVIEW

and Downstream, Chemicals & Industrial Value Chains.

A PLATFORM FOR DIALOGUE

The show will bring together policymakers, producers, investors, technology leaders and customers from around the world. Over 2,250 companies have already confirmed to participate in the show, which will take place across 16 halls and 30 country pavilions. Attendees will be able to discuss the decisions, partnerships and capital needed to expand energy supply, accelerate infrastructure delivery and strengthen long-term system performance. Different zones will address various topics including AI, carbon and chemicals, digitalisation and marine logistics, reflecting the increasing interconnectedness of modern energy systems. Christopher Hudson, President, dmg events, the organisers of ADIPEC,

said: “As the global energy landscape continues to evolve, ADIPEC’s role as a platform for dialogue, collaboration and commercial engagement has never been more important,” He continues: “Rising energy demand, supply constraints and rapid technological advancement underscore the need to bring industry leaders together to align priorities, mobilise investment and accelerate the projects and technologies required to support long-term energy security and economic growth.”

A GLOBAL MARKETPLACE

For its 2026 edition, ADIPEC will serve as a global marketplace where connections translate into commercial outcomes. In 2025, the event generated US$53 billion in value through more than 49,000 deals, demonstrating its role in advancing investment, partnerships and project delivery.

Across its conferences and exhibition, participants can align priorities, advance commercial partnerships and accelerate the projects and solutions needed to support secure, reliable and affordable energy supplies and long-term growth.

A CRITICAL TIME

Never has it been so crucial for stakeholders to have the types of conversations that happen on the exhibition floor. Despite having many reasons to cancel, ADIPEC is demonstrating why the Middle East remains firmly at the heart of the oil and gas industry. Held under the patronage of His Highness Sheikh Mohamed bin Zayed Al Nahyan, ADIPEC will take place 2-5 November 2026 at the ADNEC Centre Abu Dhabi in the United Arab Emirates. For more information visit: www.adipec.com

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SHOW PREVIEW

A TIMELY TRANSITION

ffshore Energy Exhibition and Conference is one of Europe’s leading events for the offshore energy and maritime sectors, attracting thousands of industry professionals, decisionmakers, and innovators each year. Since the show’s beginning in 2007, Offshore Energy has grown from a small gathering to a global event for industry leaders, policymakers and innovators. It is a crucial platform where oil and gas

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meets the ongoing energy transition, covering a diverse spectrum including offshore wind, hydrogen, oil and gas and marine energy. The theme of Offshore Energy 2026 is “Securing energy, sustaining the future.” Over 8,000 visitors from more than 80 countries are expected to visit this year’s exhibition and conference, which features 80+ speakers and around 500 exhibitors and partners.

WHAT TO EXPECT

Over two days, participants can attend thought-provoking conference sessions, lively panel debates and pioneering showcases. Conference sessions will examine ongoing trends from different segments of the offshore energy sector, analysing challenges and opportunities presented by the energy transition. A look at the latest innovations and developments will guide the conversations as keynotes

SHOW PREVIEW

explore various strategies to remain prepared for the future. The Square, an interactive discussion programme, is also back this year. Representatives from existing companies and startups can present their products and services in short pitches for an audience, while representatives from different markets share their knowledge on stage. Functioning as an “on air” talk hub, The Square supports an open atmosphere prime for networking.

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Meanwhile, The Stage will host thought leadership and showcase sessions, giving companies the chance to share success stories, key insights, recent projects and launches.

A NEW-FOUND RELEVANCE

Each aspect of Offshore Energy 2026 reflects the oil and gas industry’s uncertain future regarding energy security and politics. As Europe incorporates more renewables into

its grids, rising costs and instability are challenging long-term climate commitments and immediate needs. Offshore Energy 2026, organised by Navingo, will take place on 24-25 November at the RAI Amsterdam Convention Centre in The Netherlands.

For more information visit: www.oeec.biz

Gas Clip Technologies

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OFFSHORE ENERGY 2026

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Henkel

Seal Saver

Hilliard

Secc Oil & Gas

i.Safe Mobile

SubC Tech

JB Valves

UNSIG

Koso Kentintrol

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VAN BEEST - Greenpin

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VAN BEEST - Irizar Forge

Micropack

WEG

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YOUR GUIDE TO DISTRIBUTORS, SUPPLIERS AND MANUFACTURERS IN THE INDUSTRY

Böhmer

Clariant Oil Services

Gas Clip Technologies

Böhmer has focused on one product - the ball valve. The portfolio is nevertheless more than impressive: The application-optimised valves in the nominal sizes from DN 3 (1/8”) to DN 1400 (56”) are available in around 100,000 different designs.

Clariant Oil Services is a leading supplier of specialty oilfield production chemicals and services to the global oil and gas industry, delivering sustainable solutions for flow assurance, asset integrity, separation and well service applications.

Gas Clip Technologies provides a comprehensive range of gas detection solutions engineered to protect personnel in the most demanding environments worldwide, including oil and gas, chemical processing, manufacturing, and other high-risk sectors.

T +49 2324 / 7001-925

T +1 (346) 786-8312

E oertgen@boehmer.de

E oilservices@clariant.com

E sales@gascliptech.com

W www.boehmer.de

W www.clariant.com/oilservices

W www.gascliptech.com

HILLIARD

LabFacility

Plastic Coatings Ltd

Hilliard offers a diversified product line for industrial applications in a wide variety of industries. Hilliard products are designed, manufactured and sold according to our customers' applications.

The UK’s leading ISO 9001-accredited manufacturer and supplier for the complete temperature chain. From Temperature Sensors, Thermocouple Connectors and Cabling to supporting instrumentation and components, we are the GO-TO people.

The leading coating specialist, offering the widest range of coating materials and processes including Thermoset & Thermoplastic Polymers, Fluoropolymers, Electrophoretic or E-Coat Paint, PVC, Paints, Primers and more.

T +1 607 733 7121

T +44 (0) 1243 871280

T +44 (0) 1384 400066

E sales@hilliardcorp.com

E Sales@labfacility.com

E enquiries@plastic-coatings.com

W www.hilliardcorp.com

W www.labfacility.com

W www.plasticcoatings.co.uk

GET INVOLVED e advertising@setform.com t +44 (0)207 253 2545 Rotork

Seal For Life Industries

A market-leading global provider of mission-critical flow control and instrumentation solutions for oil and gas, water and wastewater, power, chemical, process and industrial applications.

Seal For Life, part of the Henkel Adhesive Technologies Group, offers the most diversified protection, maintenance and repair solutions in the market. With fourteen distinct brands offering a broad range of products servicing multiple industries across the globe.

T +44 (0) 1225 733200

T +31 599 696 170

E information@rotork.com

E info@sealforlife.com

W www.rotork.com

W www.sealforlife.com

YOUR GUIDE TO DISTRIBUTORS, SUPPLIERS AND MANUFACTURERS IN THE INDUSTRY

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Specialist Control and Choke Valve Solutions for the Global Energy Sector

MANUFACTURING SINCE 1967 As a UK-based manufacturer with over 50 years of experience, KOSO Kent Introl designs and supplies Control and Choke Valves to energy markets around the world. With deep engineering expertise and proven performance in the most demanding environments, we’re ideally placed to support the industry’s transition towards cleaner, more sustainable energy, onshore, offshore and subsea.

CONTROL, CHOKE & SUBSEA SOLUTIONS

We engineer and supply high-performance valves built to withstand some of the world’s most demanding service conditions.

SPARES

We support your investment throughout its lifecycle with genuine OEM spares, ensuring continued performance and reliability.

ASSET MANAGEMENT

Our detailed records of every valve and component we’ve ever supplied allow us to help you plan and implement a strategic approach to valve asset management.

UPGRADES

OUR SOLUTIONS

SERVICE & MAINTENANCE

With extensive in-house facilities and a responsive service team, we ensure your valves are maintained safely, effectively with minimal downtime.

As your asset’s life progresses, we can review, engineer and install suitable upgrades or replacement internals to keep your process operating at peak performance.

ADDITIVES

Using in-house Laser Powder Bed Fusion technology, our additive manufacturing team can design and produce complex components quickly and with exceptional precision.

BUMP TESTING. SIMPLIFIED. Everything you need to bump test your detector.

• 5.8L Quad Gas Cylinder - NO AEROSOL • 1’ Tubing • Thumb Press Regulator - NO WASTED GAS • Rugged Carrying Case • Fits All GCT Detectors **Detectors sold separately

AVAILABLE NOW! CONTACT SALES@GASCLIPTECH.COM FOR MORE INFORMATION