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Contents

Tom Fanchin, Senior Product Champion for Multilateral Technology, Halliburton, USA, considers multilateral slot recovery and retrofit solutions for brownfield optimisation.

05 World news 08 Navigating volatile conditions

Zara Higgins, General Manager – Saudi Arabia, and Global Head of Energy, ATPI, considers how the oil and gas sector can maintain operations when navigating volatile conditions.

24 North Sea upgrades

The discovery gap

28 The hardened FPSO

Nikhil Ati, Spandan, and Sri Kandala, McKinsey & Company, explain what the discovery gap means for oil and gas exploration.

Volume 19 Number 05

21 Unlocking bypassed reserves

03 Editor’s comment

September/October 2026

Craig Morrison, DMO Service Operations Manager, Dräger, considers gas detection and monitoring upgrades at a North Sea HP/HT platform.

Dr HyunJin Kim, Senior Vice President, Head of Technology, Hanwha Ocean EPU, and Amir Samoiloff, CEO, SIGA, comment on protecting the future of autonomous offshore operations.

The end of snapshot BOP assurance

Duco de Haan, Group CEO, MR Group, looks beyond the 14-day test at what continuous assurance means on the Norwegian Continental Shelf (NCS).

Dr HyunJin Kim, Senior Vice President, Head of Technology, Hanwha Ocean EPU, and Amir Samoiloff, CEO, SIGA, comment on protecting the future of autonomous offshore operations.

n 2015, an offshore floating platform off the coast of Africa was targeted in a cyberattack. An external adversary breached the vessel’s operational technology (OT) network, manipulating the ballast control logic to drain the pontoons on one side of the vessel. The resulting list forced an emergency evacuation and a week-long operational shutdown. The cyberthreat to the broader energy industry has grown exponentially since this incident. Recent research shows that ransomware and targeted attacks on energy organisations surged by over 900% year-over-year in 2024 - 2025. Looking forward, the offshore assets are expected to be even more of a target. First, the FPSO sector is increasingly adopting a model of Normally Unattended Installations (NUI) and fully remote-integrated operations to drive efficiency and personnel safety. The move toward total remote control removes the ‘airgap’ – the physical isolation that once kept critical systems safe from the outside world. In parallel, advances in Generative Artificial Intelligence (AI) give hostile actors more sophisticated tools to disrupt critical infrastructure. This article explores the necessity of a multi-level OT cyber strategy that integrates security directly into the physical assets and the industrial control systems. Furthermore, by integrating AI into the core of its security architecture, operators can detect and respond to sophisticated threats with the precision and technical depth required to protect an autonomous asset.

A shift to an autonomous operating model

SNAPSHOT BOP

The move toward unmanned FPSO operations is fundamentally a strategy for asset resilience. While removing the infrastructure for offshore housing and transport can reduce OPEX by 20 - 30%, the deeper driver is de-risking. Centralising operations onshore ensures business continuity during extreme weather events – like hurricanes or cyclones – that would otherwise force a total platform evacuation and a multiday production shutdown. For instance, during Hurricane Delta over 91% of production was shut down. In addition, personnel were evacuated from 42.3% of the 643 manned platforms in the Gulf. The restart period for a manned vessel can take up to a week, costing millions in deferred revenue. Furthermore, autonomy addresses a critical talent shortage. As veteran employees retire, operators are struggling to find a new generation willing to work in remote, high-hazard environments. A remote model allows a single onshore hub of experts to manage multiple assets, embedding their expertise

Duco de Haan, Group CEO, MR Group, looks beyond the 14-day test at what continuous assurance means on the Norwegian Continental Shelf (NCS). n the Norwegian Continental Shelf, proving a blowout preventer (BOP) worked last week is no longer enough. The future of well control lies in proving it is working right now. This shift is already being planned, with Havtil expected to strengthen well assurance requirements later this year, augmenting established practice. Fixed-interval BOP testing will remain non-negotiable. But as operations become more complex and cost-intensive, relying solely on a series of snapshots is no longer

28 |

16 |

Jennifer Knopf, Head of R&D Oil and Gas Product Line, and Matthew Snape, Senior Technical Commercial Manager, Vink Chemicals, discuss innovation-driven optimisation of H2S scavenging, from laboratory development to field-proven performance.

37 MAGAZINE | SEPTEMBER/OCTOBER 2026

Discover how Vink Chemicals developed a next-generation H₂S scavenger that combines faster H₂S removal with reduced chemical consumption, lower fouling risk, and improved operational reliability. From initial laboratory development to successful offshore field trials, the technology demonstrated strong performance under challenging production conditions and its potential to redefine H₂S management in oil and gas production.

33 Innovation-driven optimisation

| 17

From innovation to proven field performance:

| 29

When water stops behaving

Brent Halldorson, US Business Development Director, LiqTech International Inc., considers solutions for when produced water stops behaving and treatment still has to work.

40 Sealing the future

James Simpson, Global Segment Director, Trelleborg, emphasises the growing need for advanced validation and material testing to ensure reliable sealing components in extreme oil, gas, LNG, and hydrogen applications.

43 Optimising oil well performance

Luis Boscan, Jose Mejias and Edison Gil, OLEUM Technology, USA, explains how System of Integrated Production (SIP) uses AI-driven pressure control to stabilise oil well operations, enhance ESP performance, and increase overall hydrocarbon recovery.

46 Reading the signals

Andy Webster, Senior Director Digital & AI, KBR, explains how physicsinformed AI can help engineers interpret asset data, identify anomalies and make more informed operational decisions.

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Comment

September/October 2026

Elizabeth Corner, Senior Editor elizabeth.corner@oilfieldtechnology.com

recent report from Rystad Energy suggests that Venezuela’s oil industry could be on the verge of a significant revival, with international oil majors expanding their interests in the country and new operators entering the market.1 Chevron, Eni, Repsol and Shell are among those looking to capitalise on the country’s vast oil resources, with Rystad forecasting that production could reach 1.8 million bpd by 2030. There’s a considerable amount of work to be done before that potential can be realised: despite renewed investment interest, Venezuela reportedly had just two active drilling rigs in August, compared with the 50 or so that Rystad estimates will be needed by 2028 to support its production forecasts. Rebuilding drilling capacity, oilfield services, and infrastructure will be critical to the country’s recovery. While Venezuela’s challenge is largely one of making better use of its existing resources, there is a wider question about where the industry’s future barrels will come from. In this issue of Oilfield Technology, McKinsey & Company examines the growing gap between oil and gas production and investment in exploration (p.13). The authors point out that, while production has continued to rise, exploration spending has fallen considerably over the past decade, with companies increasingly favouring shorter-cycle projects and more immediate returns. This has resulted in declining reserve replacement, fewer major discoveries, and a potential supply shortfall of some 25 million boe/d by 2040 according to one of McKinsey’s energy scenarios. Closing that gap will require greater investment in exploration, coupled with a concerted effort to rebuild expertise, embrace new technologies, and take a longer-term view of investment. Digital technologies will have an important role to play here, particularly when it comes to improving exploration efficiency and making better use of the industry’s existing resources. In a separate report, McKinsey estimates that AI could unlock about US$65 billion of annual recurring value today, rising to as much as US$230 billion annually at full potential.2 It’s an extraordinary figure, although the authors also make the point that the opportunity is concentrated in a relatively small number of high-value applications. The challenge, then, is identifying where AI can make a meaningful difference and turning that potential into results. Several articles in this issue of Oilfield Technology explore how these challenges are being addressed on the ground. Halliburton explores how multilateral technology can unlock bypassed reserves and improve recovery from existing fields (p.21). OLEUM Technology examines the use of AI-driven pressure control to optimise well performance (p.43). And KBR considers how physics-informed AI can help engineers interpret asset data and make more informed operational decisions (p.46). Each offers a practical perspective on how technology and innovation can help the industry make better use of its resources and improve performance. As the industry gathers in Abu Dhabi for ADIPEC, there will undoubtedly be plenty of ambitious forecasts, new technologies and investment opportunities to discuss. But perhaps the more interesting question is not what the upstream sector could achieve, but what it will take to deliver on that potential. At Oilfield Technology, we’ll continue to focus on both: the opportunities ahead, and the technologies, expertise and innovation needed to turn them into reality. 1. 2.

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September/October 2026 Oilfield Technology | 3

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World news

September/October 2026 In brief

SLB and TotalEnergies welcome Chevron to collaboration

Norway

SLB has announced that Chevron Technical Center, a division of Chevron U.S.A. Inc., has joined the long-term digital subsurface collaboration established by SLB and TotalEnergies in 2024, adding a second global operator to the co-development of next generation digital technologies for reservoir engineering and geoscience. “This collaboration brings SLB’s digital and subsurface expertise together with operator knowledge to help develop technologies for reservoir engineering and geoscience,” said Rakesh Jaggi, President of SLB’s digital business. “Chevron adds valuable experience and perspectives that will help strengthen how we address complex subsurface workflows and field development decisions.” Chevron will contribute investment, intellectual property and technical expertise to the collaboration. The company will also bring industry-leading expertise in uncertainty analysis, optimisation and field development planning, that will help shape the roadmap for scalable digital subsurface technologies. As operators manage increasingly complex reservoirs and growing volumes of subsurface data, the collaboration, known as Arena, will focus on technologies that help improve decision-making across reservoir engineering and geoscience workflows. “Chevron is working to advance digital capabilities to unlock greater value from our subsurface resources,” said Jitendra Kikani, Chevron Vice President of Subsurface. “Through Arena, we are combining our world-class expertise in uncertainty analysis with digital technologies and AI-enabled workflows to improve decision quality, accelerate insights, and enhance operational efficiency.” Chevron, Total, and SLB are building upon their successful collaboration that delivered the industry-leading Intersect simulator. Arena represents another step forward in transforming subsurface decision-making.

Rystad Energy: Venezuela’s oil sector comeback Venezuela’s upstream oil sector is attracting its broadest pool of international operators and capital in decades, with established majors expanding their footprints and new operators entering under revised contractual frameworks. If capital deployment, rig availability and oilfield services scale in line with requirements, Rystad Energy models Venezuelan crude production reaching around 1.6 million bpd by 2028 and 1.8 million bpd by 2030. “The roster of companies now actively looking to expand or operate in Venezuela is genuinely different from anything we have seen in years. Established operators are taking on larger roles and new names are entering the market. A wider group of operators should help mobilise the capital and activity needed to rebuild rigs, oilfield services and infrastructure across the entire supply chain,” said Radhika Bansal, Senior Vice President, Oil and Gas, Rystad Energy. Chevron has added Carabobo-1 and Carabobo-2-Sur-A to its portfolio and outlined more than US$7 billion in investment over five years. Eni has taken exclusive operatorship of Junin 5 under a new 25 year production participation contract. Repsol has regained operational control at Petroquiriquire, and Shell has re-entered through redevelopment agreements for Carito and Pirital. New entrants include regional independent GeoPark, Texas-based Hunt Oil and Brazilian independent Fluxus Oil, Gas & Energy, while North American Blue Energy Partners (NABEP) has substantially expanded its existing position through a framework covering 17 producing and development areas. Rystad Energy favours investment programmes tied to established operators and defined assets over larger ambitions requiring substantial external capital. NABEP’s US$100 billion figure represents a long-term funding requirement, not committed near-term capital, and the company has not disclosed a detailed financing structure. The more binding constraint is operational, with Baker Hughes reporting just two active drilling rigs in Venezuela as of August, against a Hydrocarbons Ministry target of around 93 rigs by 2028. The oilfield services supply chain is beginning to rebuild, SLB has around 15 rigs positioned in Venezuela that could potentially be reactivated within a year.

Wood Mackenzie analysis finds that record premiums for Johan Sverdrup crude could deliver a major cashflow boost for the field’s partners and significantly increase Norwegian state revenues in 2026.

Singapore Seatrium and Karpowership are expanding their floating LNG partnership with the award of a ninth FSRU conversion project, LNGT Akdeniz, scheduled to begin in 2027.

Southeast Asia Rystad Energy expects Southeast Asia’s upstream M&A market to shift from IOC divestments towards strategic acquisitions, with US$9.6 billion of assets set to come to market through 2027.

Oman Black Rock Oilfield Technology supported an operator in successfully delivering its first offshore TAML Level 5 multilateral well, with zero reported non-productive time during the operation.

Norway Flylogix has completed a landmark cross-border drone flight from the UK to Norwegian waters to survey methane emissions from Equinor’s Statfjord B platform.

Indonesia STRYDE will supply 12 000 seismic nodes and its Nimble Seismic Acquisition System to PT SUCOFINDO, expanding the use of lightweight nodal seismic technology in Indonesia.

Canada WellSense has partnered with Precise Downhole Solutions to expand access to its fibre optic well surveillance technology across Canada, following successful initial deployments in Alberta.

September/October 2026 Oilfield Technology | 5

World news

Diary dates

02 - 05 November ADIPEC 2026

Abu Dhabi, UAE www.adipec.com

06 - 07 April 2027 SPT Brazil 2027

Rio de Janeiro, Brazil https://sptcongress.com/

16 - 17 June 2027 Energy Projects Conference & Expo Houston, USA https://www.epcshow.com/

Web news highlights Ì Decom Mission and FINDES launch

September/October 2026

Petrobras, Shell and Strohm complete qualification and field trial programme for ultra-deepwater TCP flowline

Strohm has completed a joint industry programme (JIP) with Petrobras and Shell for its Thermoplastic Composite Pipe (TCP) flowline technology. The project, comprising of a full-scale qualification and extensive offshore field trial, is the world’s most advanced initiative to bring TCP flowlines offshore under actual field conditions, and it has the potential to revolutionise the deepwater market in Brazil and beyond with a corrosion-free flowline solution that has a 30 year design life. The region’s prolific pre-salt provinces have some of the most productive wells in the world. However, the high CO2 concentrations in these fields have been reported to lead to premature failure of conventional flexible pipes. These failures are caused by stress corrosion cracking, an aggressive form of corrosion caused by the presence of CO2; avoiding such failures requires operators to replace the conventional flexible flowlines regularly, in turn leading to deferred production. The JIP programme delivers the first fully qualified flowline designed to meet the most onerous conditions of the Brazilian pre salt, including operation in environments with a high CO2 content, for a service life of 30 years. Building on Strohm’s systematic qualification methodology, the programme included system-representative testing that validated the interaction between the pipe, end-fitting and sealing interfaces under realistic operating conditions, ensuring a robust and predictable performance throughout the entire system lifecycle.

portal connecting Brazilian decom with UK expertise

UK expertise can help accelerate significant CCUS deployment across Asia Pacific, Xodus study finds

North Sea contract

UK expertise in carbon capture, utilisation and storage (CCUS) can accelerate the development of projects across Asia Pacific, according to new analysis from global energy consultancy Xodus. The Asia Pacific (APAC) region is responsible for more than half of global carbon dioxide emissions and is expected to become a significant global centre for CCUS deployment. Xodus’ APAC CCUS Regional Assessment, which was commissioned by the UK Department for Business, Innovation, Science and Trade, identifies a strong alignment between CCUS challenges in APAC and areas in which the UK has developed specialist capability through the development of its own CCUS industry. These include subsurface appraisal and saline aquifer screening, CCUS regulatory and monitoring frameworks, early-stage feasibility and FEED, specialist capture technologies, Monitoring, Reporting and Verification (MRV), and engineering and design for CO2 transport and shipping infrastructure. Andrew Taylor, Head of Advisory, APAC, Xodus, said: “Asia Pacific does not lack ambition or potential for CCUS but its challenge is turning that potential into investable projects. Across the region there are countries with significant emissions and very substantial storage resources, plus governments developing the frameworks needed to connect the two. But there needs to be further work on storage characterisation, regulation, pro-ject development and specialist engineering if deployment is going to accelerate. “The UK has already developed solutions to many of these challenges in pursuing its own CCUS industry. Applying that experience in partnership with governments, project developers and local supply chains across Asia Pacific can help projects progress more quickly and avoid having to solve the same problems again.” The study highlights the increasingly interconnected nature of the regional CCUS market. In Northeast Asia, countries including Japan, South Korea, and Taiwan are expected to initially focus on validating local storage, capturing and exporting CO2, while Malaysia and Indonesia have the potential to become major storage locations for both domestic and imported emissions. Australia and New Zealand also offer significant geological storage opportunities, although greater transport distances could affect the economics of importing CO2 from Northeast Asia. This geographic mismatch between major sources of emissions and available storage means cross-border transport and common regulatory and technical frameworks are likely to become increasingly important as the industry develops.

Ì TWMA secures multi-million-pound UK Ì SCA wins Saipem contract for cable transportation and transpooling services in the Caspian

Ì Baker Hughes collaborates with OGDC to optimise existing well production, supporting energy continuity in Pakistan

Ì New Echo division launched to fasttrack seismic insights for high-risk projects

Ì Viridien launches onshore Sabah

multi-client prospectivity study in Malaysia

Ì Emerson to build new automation solutions service centre in Qatar

Ì KBC updates Maximus production modelling platform

Ì DNV acquires Equinor digital solution to enhance subsea wellhead fatigue management

To read more about these articles and for more event listings go to:

www.oilfieldtechnology.com 6 | Oilfield Technology September/October 2026

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Zara Higgins, General Manager – Saudi Arabia, and Global Head of Energy, ATPI, considers how the oil and gas sector can maintain operations when navigating volatile conditions. il and gas is a complex, high-pressure environment with little margin for error. Success depends on precision, coordination, and having the right people, in the right place, at the right time. It is a sector with complex operations and high expectations, and the margin for error is incredibly small. Every element of the operation must align, from the equipment and infrastructure to the timing and, most critically, the people. But what happens when skilled crew and personnel cannot travel or reach a site as planned? In an industry where continuity depends on people being exactly where they need to be, workforce mobility is not simply a travel requirement, it is an operational necessity. This is a scenario many Middle East operations have had to confront this year following heightened regional tensions, which created significant uncertainty around the movement of people, assets and critical resources. The escalation of conflict involving the United States, Israel, and Iran from February placed the Middle East firmly at the centre of global attention, with businesses assessing what further disruption could mean for their people, supply chains and operations. Few industries are more exposed to that uncertainty than oil and gas. The region remains fundamental to global energy production and trade, and disruption to key routes such as the Strait of Hormuz has reinforced just how quickly geopolitical events can become significant operational challenges. In periods of heightened uncertainty, the ability to mobilise people safely, uphold duty of care and maintain operational continuity comes under intense scrutiny. Businesses must be able to respond quickly and adapt confidently, without compromising the wellbeing of the people at the heart of their operations. Mobility in times of uncertainty The Middle East sits at the heart of global O&G employment. The International Energy Agency’s ‘World Energy Employment 2025’ report highlighted that around 20% of the sector’s global workforce operates across the region, while other research suggests that expatriate and migrant workers account for a significant proportion of the Middle East’s energy workforce. Put those figures together and the picture is clear, the industry is heavily dependent on logistics, travel and the ability to move people efficiently.

When airstrikes began in February, the challenge was real. Crews, including those travelling for work and those living locally with their families suddenly faced uncertainty around whether they could travel, where they could travel to and how quickly they could move if circumstances deteriorated. As a global travel management partner to the oil and gas industry, ATPI naturally became a first point of contact for many organisations navigating the disruption. What companies required in those moments went far beyond just booking flights, accommodation, and ground transportation. They needed clarity, options, and reassurance in a time of need. Experiences such as this, alongside major global disruptions including the COVID-19 pandemic, have reinforced the importance of managing not only travel, logistics, and workforce mobility, but also the human emotion associated with high pressure situations. Calm, clear, and compassionate communication becomes just as important as finding the next available route. As the operating environment shifted, ATPI’s regional and international teams moved quickly to help organisations and their people understand what options were available. Working across airlines, aviation authorities, regulators, consulates, and embassies, our role was often to connect the realities on the ground with the operational decisions businesses needed to make. This was no simple task and pressure across key transport routes and regional hubs created challenges, with reduced seat availability which created significant pricing volatility. Plans that may have been straightforward only hours earlier suddenly required alternative routings, greater flexibility, and constant reassessment. For personnel mobilised to offshore installations, remote project sites, and critical infrastructure, the challenge was

Figure 1. The oil and gas industry relies on complex operations and

high expectations; making travel management support integral to operations.

Figure 2. Travel technologies such as ATPI CrewHub make workforce

mobility and group travel a simplified process.

10 | Oilfield Technology September/October 2026

often even greater. Limited accessibility, rotation schedules, and operational requirements introduced additional layers of complexity. Flexibility across travel, logistics, and operational teams became essential, while transparent, round-the-clock communication played a critical role in supporting wellbeing and preventing uncertainty from escalating into unnecessary stress. Resilience is fundamental to the oil and gas industry, and it is really put to the test during periods of geopolitical volatility. Resilience is not simply the ability to react when disruption occurs, it comes from preparation, open communication and a coordinated strategy involving operations, travel, duty of care, and specialist partners. That approach allows contingency planning to become structured rather than reactive and enables workforce mobility, repatriation or evacuation to be managed as safely and seamlessly as circumstances allow. It is what enabled ATPI and its clients to explore alternative routing, secure greater accommodation flexibility, and maintain close coordination between travel, operations and duty of care teams throughout periods of uncertainty.

Why updated technology and systems matter

Just like every facet of oilfield operations, technology plays a critical role in how effectively people carry out their responsibilities. Workforce mobility and travel management are no different, particularly in the Middle East where operations are heavily dependent on moving people across borders in line with visa, work permit, and regulatory requirements. Realtime visibility, automation, continuous communication, and data driven decision making have all been strengthened by advances in technology, and these capabilities have played an important role in helping businesses operate through periods of volatility. During the COVID-19 pandemic, many organisations were forced to reassess how they operated and make strategic changes to better support their people and long-term objectives. It demonstrated that even in the most challenging conditions, businesses can adapt, improve, and emerge stronger. For travel management companies operating in complex fast-moving markets, disruption does more than test systems and processes. It exposes weaknesses, highlights gaps and creates an opportunity to rethink how travel is managed. In recent years this has resulted in many organisations to consolidate suppliers, improve policy compliance, introduce greater traveller visibility and re-design approval processes. This has resulted in more efficient and resilient operating models. When immediate pressures ease, the response should not simply be ‘business as usual’’. It should be an opportunity to review the entire workforce mobility ecosystem, from planning, requests, and approvals through to traveller tracking, spend governance, and reporting. The Middle East also presents operating challenges that differ from many other major energy markets. Remote and desert locations require specialised logistics, geopolitical conditions can increase safety and duty of care requirements, while visas and work permits remain highly regulated. For organisations dependent on international workforces, these

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are not occasional considerations, they are part of everyday operations. Technology can help organisations manage that complexity by combining intelligent systems with operational expertise, giving decision makers greater visibility, and enabling them to respond quickly as circumstances change. As a travel management partner, our role is to help clients maintain visibility of their people regardless of the conditions around them. It is not simply about responding more effectively when disruption occurs, it is about building workforce mobility programmes that are more resilient, transparent and aligned with the realities of the operating environment. When planned right, this reduces complexity, removes friction for travellers and operational teams, strengthens duty of care and creates a mobility programme that is better prepared for whatever comes next.

Case study: supporting workforce evacuation in Iraq

When conflict between Iran, the US, and Israel first began earlier in 2026, uncertainty and anxiety arrived at the doorstep for thousands of overseas employees working in the region at an instant. The reality of their personal and professional lives changed dramatically, with many left in challenging and uncertain circumstances. For employers, the balance between business activity and the duty of care they owed to their employees had rarely been a more challenging one to navigate. Disruption and situations similar to those experienced this year are by no means revolutionary. Sadly, they are not uncommon for those working in volatile markets and regions. But that doesn’t negate any of the stress, fear, or disorder experienced since February; instead, the scale of the growing tensions was new to many. To help navigate operations and duty of care requirements, ATPI’s regional teams across the Middle East worked together to support the industry with expert travel services. The situation As regional tensions escalated across Iraq and the wider Middle East, an energy services and engineering company with operations in the region faced the urgent challenge of relocating personnel from an increasingly uncertain operating environment. The requirement began as a precautionary drawdown of non-essential personnel ahead of the conflict involving Israel, the US, and Iran, before developing into a wider workforce evacuation involving more than 150 personnel. Travel conditions were increasingly complex. Flight availability was limited; routing options varied depending on nationality and visa eligibility, and arrangements were required at short notice across multiple borders and departure points. Through the client’s established travel programme with ATPI, traveller profiles and travel data provided visibility of employees in-country, in transit and due to travel, helping support planning and coordination as the situation evolved. The challenge The evacuation required careful coordination across travel, HR, HSE, and security teams while managing a fast-moving operational environment. Initial support began in late February, when the client requested assistance to move non-essential personnel out 12 | Oilfield Technology September/October 2026

of Iraq as a precautionary measure. With same-day travel requirements and limited airline availability, flights and transit accommodation needed to be secured quickly. As the wider drawdown operation commenced in early March, the complexity increased. Personnel required different evacuation routes based on visa eligibility and border access, while travel plans needed to remain flexible to respond to changing operational conditions. Maintaining accurate, real-time updates between all stakeholders was critical throughout the process. The response ATPI worked alongside the client’s travel, HR, HSE, and security teams to support planning and coordinate personnel movements throughout the evacuation period. An initial planning call was held in March to review available options and establish workable evacuation routes. From there, dedicated communication channels enabled regular status updates and live coordination between operational teams. The first phase focused on the precautionary relocation of non-essential personnel. Despite limited availability and short lead times, flights and transit accommodation were secured, and personnel departed on a range of available services to their home countries. As the wider evacuation programme progressed, routing was coordinated according to visa eligibility and border access requirements. Personnel eligible for visa-on-arrival access travelled via Kuwait and Saudi Arabia, supported by coordinated accommodation, onward ground transportation and international departures. Alternative routes were arranged via Turkey for personnel unable to transit through Kuwait. These journeys involved coordinated land movements, overnight accommodation where required and onward flights from regional airports based on the nearest available capacity. Throughout the operation, travel teams worked extended hours and maintained regular communication with the client and operational stakeholders to provide updates on traveller movements and support decision-making at key stages of the evacuation. The outcome Over a seven-day period, more than 150 personnel were successfully evacuated from Iraq through multiple international routes despite limited flight availability, changing border requirements and heightened regional instability. The operation enabled the client to maintain visibility of personnel movements while supporting safe relocation and continuous communication throughout the evacuation process. The client formally recognised the collaborative effort involved, highlighting the responsiveness, flexibility, and operational support provided during the evacuation, noting that “ATPI’s responsiveness, flexibility, and willingness to work extended hours to arrange visas, transport, hotels, and flights, and to continuously monitor movements, was critical to the success of this operation.” The work between ATPI and the client was just one of several similar cases in the same time period, demonstrating how operations and duty of care can coexist even in the most challenging and unruly circumstances.

Nikhil Ati, Spandan, and Sri Kandala, McKinsey & Company, explain what the discovery gap means for oil and gas exploration. ll energy outlooks point to ongoing oil and gas demand through 2040, even as recent investment in exploration has lagged. Addressing this mismatch will require a strategic reset. For decades, oil and gas exploration drove industry growth with enormous implications for countries and regions where resources were discovered. After low investment in the late 1980s and early 1990s, the industry ramped up exploration spending through the late 1990s and early 2000s to restore depleted reserves and balance supply and demand. Over the last ten years,

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however, exploration and production have decoupled – Limited exploration is widening the oil and gas production has continued to grow as exploration spending supply gap has declined. Capital spending on exploration has never The transition to a decarbonised energy system will need been so low relative to production (Figure 1). to balance affordability, energy security, reliability, and During this period, capital migrated to short-cycle competitiveness. A range of possible pathways could achieve projects such as onshore shale and offshore tiebacks. this transition, each of which carries uncertainties. Yet in two Further, uncertainty about the pace of the energy transition of the three energy transition scenarios outlined in McKinsey’s and investor demands for returns shifted companies’ Global Energy Perspective (GEP), oil and gas demand grows focus toward immediate cash generation and away from by several percent by 2030. As production from existing wells many of the strategic and operational capabilities needed declines faster each year, new discoveries will be needed to for exploration. Many companies now face hollowedmeet demand in any of the scenarios. GEP projects a shortfall of out exploration teams, long cycle times, increased unit approximately 25 million boe/d by 2040, under the Continued exploration costs, and low success rates. With demand Momentum scenario (Figure 2), relative to existing and fully still rising and well production decline rates accelerating, invested supply sources. reserves cannot be rebuilt without renewed exploration. Even as this gap has widened, exploration success In this article, we examine the widening supply-andrates have plateaued, and total discovered resources in Web 2026 demand gap facing the oil and gas industry and outline the last decade have fallen by more than 50%, from 331 to Pub-DiscoveryGapOilGas Exhibit 1 of 6 the strategic, operational, and capability shifts required to 156 billion boe. Apart from the Guyana breakthrough, no rebuild reserves and meet projected demand. sizeable basin has emerged in the last decade. Most other finds Oil and gas exploration investment today is out of balance with production. are infrastructure-led, meaning that they are adjacent Global liquids production and corresponding exploration spend, annual and incremental to existing production areas. While such Era: Underinvestment Robust exploration Declining investment driven by sites have attractive net present values (NPVs) owing to in exploration investment uncertainty in energy transition limited additional infrastructure needs, which helps with Global liquids production, million barrels per day Oil and gas exploration capex, $ billion both cash flow and timing, they typically do little to shift 120 120 the reserve base. 12% 1% As a result, reserve-replacement ratios have fallen 100 100 –6% to historic lows across the sector. Many companies are 1% producing far more oil and gas than they are discovering, 80 80 CAGR which shrinks future portfolios, compresses future 1% earnings potential, and reduces investor confidence. 60 60 Some companies have increased their reserves through M&A, but such transactions do not add barrels to the 40 40 global oil and gas supply. CAGR 1

0 1985

0 1995

2005

2015

2025

–1%

Exploration portfolios lack more than capital 1985

1995

2005

2015

2025

Liquids include crude, condensate, natural gas liquids. Source: Rystad UCube (Oct 2025)

McKinsey & Company

Figure 1. Oil and gas exploration investment today is out of balance with

production: global liquids production and corresponding exploration spend, annual.

Capital retreat is a major reason why exploration has declined, but it isn’t the only one. It is one of six headwinds that have depressed outcomes and eroded exploration portfolio value.

Reduced capital investment

Capital investment in exploration was robust in the late 1990s and early 2000s, with exploration capital expenditure growing approximately 11% annually, often outpacing the approximately 10% annual oil-price gains. Since the 2014 - 2015 price crash, however, exploration spend has fallen approximately 6%/year. Exploration activity has mirrored the trend: from 1995 - 2014, the number of exploration wells drilled grew approximately 6%/y, but over the past decade they have declined by an average of approximately 12%/y. If the current pattern of limited exploration continues, operators may be forced to rely on higher-cost, more carbon-intensive barrels.

Rising costs and lengthy timelines

Figure 2. By 2040, new upstream developments will be needed to satisfy oil

demand across all scenarios. Global oil demand and production, by production status, millions bpd.

14 | Oilfield Technology September/October 2026

On the production side, core operations have progressed rapidly down the learning curve, shortening cycle times and significantly reducing supply chain costs as output has continued to grow. On the exploration side, however, a combination of reduced management focus, depressed levels of activity, and depletion

of easier-to-find barrels has resulted in relatively fewer improvements in cycle time and costs. Finding costs per barrel – a measure of how much exploration adds to the cost of each barrel – continue to climb, as discovered resources decline. End-to-end cycle times, from the first seismic explorations of an area to the first oil from a well, average approximately 20 years, making exploration of new areas less attractive relative to incremental step-outs.

Immediate cash generation crowding out long-term value creation

Over the last decade, equity analysts (and hence the industry) have focused on immediate cash generation, heavily discounting future earning potential. Given an uncertain energy transition pathway, investors have tended to be risk averse about oil and gas returns. This pushed companies to optimise near-term cashflow and allocate more capital to short-cycle opportunities. Long-dated options that could build large future reserves were frequently deprioritised.

Suboptimal risk frameworks impacting exploration portfolio decisions

Preference for safer, smaller near-term opportunities has diluted portfolio optionality. Risk frameworks remain anchored to rigid return thresholds that can undervalue the creation of strategic options. This issue is typically more pronounced in organisations that make exploration decisions at the regional level, because many “high risk, high return” opportunities that would offer diversification within a centralised portfolio are too risky for any single region to pursue alone.

Talent and experience erosion

A decade of underinvestment in exploration left roles vacated by retirements unfilled, while mergers thinned teams and eroded institutional memory. Beyond headcount, there is a loss of expertise from lived experience: prior generations built skills across many more basins and play types, giving them a deep catalogue of analogs to draw on. Many companies now lack the geoscience and project-delivery depth to execute ambitious programmes.

Higher technical uncertainty and constrained seismic access Few remaining prospects have clear seismic or geophysical signatures, increasing uncertainty in technical assessments and making portfolio outcomes less reliable. At the same time, a retrenched seismic industry, with minimal multiclient activity and limited new basin imaging, raises the cost and difficulty of unlocking new basins and plays, further limiting access to promising opportunities.

Resetting approaches to exploration could help close the supply gap Bridging the supply-demand gap in oil and gas exploration will require companies to make integrated shifts in strategy, operations, and capabilities, encompassing the following components:

Strategy: build an advantaged, risk-savvy portfolio Develop an exploration target that aligns with the longterm energy outlook, including the expected supply gap, and support it with long-term capital commitment.

Ì Optimise portfolios for risk-return at the central (rather Ì Ì

than regional) level, which will allow for better risk management. Balance capital allocation between basins with step-change future potential and near-field opportunities that allow immediate cash flow. Use partnerships, farmouts, and alignment with national oil companies and host governments to manage portfolio-level risk and secure advantaged acreage and access. Embed risk-based decision-making into the strategic process instead of looking to eliminate all risk. Shift from rigid return-rate thresholds to probabilistic, portfoliobased decisions to enable bold bets at the portfolio level.

Operations: prioritise speed and commercial discipline Replace slow, siloed governance, often at the regional level, with empowered accountable teams and rapid stage gates. Compress cycle times – moving from seismic exploration to first drill in months, not years – with simplified approvals that reward speed, learning, and disciplined iteration. Normalise quick fails through setting upfront decision criteria and exit thresholds. Instil end-to-end accountability that prioritises commercial value over the number of barrels. Shape opportunities early, considering cost, mode of production, route to market, and carbon intensity so that finds are financeable and fast to monetise. Identify the key competitive drivers for exploration – whether cycle time, finding costs, access to acreage, or availability of key partners – and embed them within operations to enable cross-functional collaboration and agility.

Ì Ì Ì

Capabilities: build a tech-enabled capability edge Adopt an explorer’s mindset that includes making commercial-first choices: Prioritise speed to revenue, manage risk at the portfolio level (not prospect-byprospect), apply rapid learning loops, use data-led judgment, and execute as an integrated team. Apply AI and machine learning to accelerate seismic interpretation, reduce bias, improve risk evaluation, and rank prospects more accurately. Integrate data sources to compress cycle times. Invest to rebuild capabilities by training the next generation of geoscientists, reservoir engineers, and data scientists, and institutionalising mentorship and knowledge transfer. Broaden the talent base by recruiting from adjacent fields, including data science and machine learning, and form cross-functional squads to inject fresh thinking into exploration workflows.

Ì Ì Ì Ì

Closing the gap between projected supply and demand will likely require a step change in oil and gas exploration. This would involve prioritising commercial barrels, moving faster with agile governance, modernising risk frameworks to back more and bigger bets, and deploying digital capabilities and AI to compress cycle times and improve hit rates – all while delivering strong risk-adjusted returns and lower environmental intensity to meet investors’ expectations. With renewed talent, strategic partnerships, and a focus on advantaged resources at scale, exploration can play a decisive role in securing future oil and gas supply. September/October 2026 Oilfield Technology | 15

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Traditional assurance models were built around one core idea: test at fixed intervals, document the result and demonstrate compliance after the fact. That model has underpinned decades of safe operations and remains

Figure 1. Assessing the data: live offshore monitoring from ModuSpec’s

Houston control room.

fundamental to well integrity. But it inevitably leaves a visibility gap between test events. Modern BOP control systems generate a rich stream of operational data – pressures, volumes, cycle counts, temperatures, timing. Too often, that information is checked reactively when something looks wrong rather than being trended as part of a formalised monitoring framework. The result is a disconnect between regulatory intent – which increasingly emphasises documented condition monitoring and failure tracking – and day-to-day offshore practice, which can still rely heavily on periodic testing alone. On the NCS, where regulators are already looking harder at how assurance is achieved in practice rather than simply whether the right documents exist, that disconnect will become increasingly difficult to defend. Real-time BOP monitoring is not about replacing traditional testing. It provides continuity between tests. A pressure test can tell you that a function worked at 10:00 on a Tuesday. It cannot tell you whether closing volumes have been creeping up over the past six weeks, or whether a subtle hydraulic loss is accelerating. When structured properly, digital monitoring tools trend and document that performance over time. They can reveal, for example, that every time an annular is cycled, more fluid is required to close it. This is an early, quantifiable signal of wear that can be addressed before it becomes a problem. They can also reduce unnecessary cycling by supporting more precise intervention decisions, protecting both equipment and uptime without altering the underlying safety intent.

Decision confidence

Figure 2. BOP RTM dashboard.

Figure 3. DPT dashboard.

Figure 4. Fleet overview dashboard.

18 | Oilfield Technology September/October 2026

This is why continuous monitoring should not be seen primarily as a compliance exercise or purely as a risk reduction measure. Its core value is decision confidence. Compliance defines the framework, risk reduction is the outcome. The continuous performance evidence in between is what allows engineers and offshore leaders to make defensible calls on testing frequency, maintenance timing and deployment duration. The NCS is well suited to this evolution. Strong regulatory oversight, high technical expectations and a culture that prizes documentation and traceability are already embedded. Structured condition monitoring, formal failure tracking and clear performance records fit naturally into that environment. But in a high-trust regulatory regime, credibility cannot rely on self-certification. Monitoring tools influence decisions around safety-critical equipment, so the question “who checked the checker?” is entirely legitimate. That is why independent technical qualification has become such a decisive factor on the NCS. When assurance tools are subject to external scrutiny, whether by Havtil or recognised third parties, the standard shifts from “it works” to “it is demonstrably robust and defensible”. External review forces greater discipline in data handling, analytical methods, failure logging, and documentation. It ensures that monitoring outputs can withstand technical challenge in a regulator’s office just as well as they support decisions in a control room offshore. If the NCS does move towards more formalised continuous assurance requirements, the differentiator will not be who has the cleverest algorithm. It will be who can integrate digital assurance into how they actually work.

Assurance often struggles in practice because of human factors: time pressure, procedural drift, and the natural tendency to rely on experience and judgment when information is incomplete. Digital tools can counter this by standardising analysis and highlighting anomalies objectively, but only if they are embedded in daily workflows and supported by proper training, not bolted on as an afterthought. Different functions will continue to view assurance through different lenses. Drilling teams focus on reliability and disruption, HSE on risk control and documentation, senior management on exposure and long-term integrity. Shared, structured performance data Figure 5. Rig overview dashboard. is one of the few things that can align those perspectives. When everyone is looking at the demonstrate not just that they have the tools, but that those same trends, the same failure records and the same case files, tools are integrated into engineering practice and are improving conversations move from opinions to evidence. the quality and defensibility of decisions. In a basin where trust is earned through evidence, Earning trust continuous assurance is not a regulatory threat. It is the logical Automated monitoring should be treated as decision support, next step in Norway’s long tradition of taking well control not a decision maker. AI and advanced analytics can surface seriously – and it will reward those who move early. patterns and anomalies more consistently than manual review, but interpretation and accountability must remain with About the author experienced personnel and engineering leaders. Duco de Haan is Group CEO of MR Group, managing Whether or not continuous assurance becomes a formal businesses including ModuSpec. He has more than 32 years’ regulatory requirement on the NCS, the direction of travel is experience in upstream oil and gas operations, spanning clear. Extended test intervals will only be accepted where they consultancy, compliance, inspection and commercial are supported by credible, structured, real-time monitoring. leadership across Asia Pacific, the Middle East, Europe, Africa, The operators who earn that latitude will be those who can and Russia.

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Tom Fanchin, Senior Product Champion for Multilateral Technology, Halliburton, USA, considers multilateral slot recovery and retrofit solutions for brownfield optimisation. s oil and gas assets mature, operators face increasing pressure to maintain production while managing economic and infrastructure limitations. Declining reservoir pressure, rising water production, slot constraints, and marginal drilling economics have shifted industry focus to maximise recovery from existing assets. Brownfield context and the case for multilaterals Well slot availability remains one of the most significant challenges in mature developments. Many offshore platforms were designed with finite drilling and production capacity based on original field life expectations. As reservoir understanding improves, operators often identify bypassed

reserves, reservoir compartments, and infill opportunities that remain economically attractive but difficult to develop within existing infrastructure and well slot capacity. In this environment, multilateral well technology has become an effective redevelopment solution. By accessing multiple reservoir compartments from a single surface wellbore, multilateral systems increase reservoir exposure and minimise the requirement for new infrastructure. Advances in junction systems, drilling techniques, and intelligent completions improve reliability and expand the use of multilaterals in brownfield developments. Two common brownfield applications are slot recovery and retrofit multilaterals. Both approaches aim to improve

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recovery, extend field life, and reduce redevelopment costs, but they are used in different situations: slot recovery replaces an underperforming well from the same surface slot, while retrofit multilaterals add reservoir access without abandoning a productive wellbore. Slot recovery involves permanently abandoning an existing well and drilling a replacement multilateral well from the same surface slot to access bypassed reserves and increase reservoir exposure. One or more lateral branches can then be drilled from the new wellbore to improve drainage efficiency. Retrofit multilaterals preserve the existing producing wellbore while adding one or more lateral branches to access additional reserves. Instead of abandoning a productive well, operators temporarily isolate the main bore during drilling operations and then restore production from both the original wellbore and the new laterals.

Slot recovery and new opportunities from existing infrastructure

Slot availability remains a key challenge in offshore brownfield developments. Many mature platforms operate near or at slot capacity, limiting opportunities for new drilling despite the presence of untapped reserves. Improved reservoir characterisation often identifies bypassed reserves that the original well architecture could not efficiently drain. Slot recovery addresses this challenge by repurposing existing infrastructure based on updated reservoir understanding (Figure 1). After an underperforming or depleted well is plugged and abandoned, a replacement multilateral well is drilled from the same surface slot to access bypassed reserves in poorly drained reservoir compartments and improve recovery. A key advantage of slot recovery is the ability to optimise the replacement well trajectory without being constrained by

the original well design. The new main bore and laterals can be positioned to maximise reservoir exposure, improve sweep efficiency, and target reserves identified through production history, reservoir surveillance, and modern subsurface analysis. This flexibility is particularly valuable in mature assets where earlier wells were drilled with less complete reservoir understanding or lower-resolution seismic data. Slot recovery can reduce well count by accessing multiple targets from a single slot. This approach reduces facility modifications, lowers drilling and completion costs, and minimises disruption to existing platform operations. In some cases, slot recovery also addresses mechanical integrity issues in aging wells. Older completions may experience tubing degradation, causing damage or production constraints that make ongoing intervention uneconomic. Replacing these wells with modern multilateral completions can improve long-term reliability while increasing access to bypassed reserves. Slot recovery is not always the optimal solution. Some wells remain economically productive because of their favourable trajectory or access to existing infrastructure, making operators reluctant to abandon them solely to access nearby reserves. In these cases, retrofit multilaterals provide an alternative that expands reservoir access while preserving the existing wellbore.

Retrofit multilaterals and expanding reservoir access without well abandonment

Retrofit multilaterals preserve the existing producing wellbore while adding lateral branches to increase reservoir exposure. Rather than abandoning a productive well, the original wellbore is temporarily isolated while new laterals are drilled to access bypassed reserves or undrained reservoir compartments. Production can then resume from the original interval and the new laterals, increasing recovery without additional well slots or major infrastructure expansion. The primary objective of retrofit multilaterals is to increase production, accelerate reserve recovery, reduce reservoir drawdown, and mitigate water production while maintaining output from the existing wellbore. This approach is valuable in mature fields where significant hydrocarbon volumes remain stranded in compartmentalised or poorly drained reservoir areas near existing infrastructure. Retrofit multilaterals are attractive where infrastructure constraints limit new drilling opportunities (Figure 2). By reusing existing wellbores and facilities, operators can avoid the costs of drilling new top-hole sections, modifying facilities, and abandoning existing wells. This Figure 1. Slot recovery well path; dual-lateral well and the two tri- lateral reentries improves the economics of accessing remaining with 111 748 ft cumulative reservoir contact (Kelsey et al. 2022). reserves that may not support standalone development wells. Candidate selection typically requires suitable bypassed reserves, adequate well integrity to support multilateral installation, and economics that meet investment criteria. Success is measured by the ability to increase reservoir exposure and deliver sustained production within planned cost and schedule targets. This approach supports improved reservoir management and long-term field optimisation as reservoir conditions evolve. Figure 2. Retrofit installation schematic (Kelsey et al. 2021). 22 | Oilfield Technology September/October 2026

Advances in multilateral junctions, zonal isolation technologies, and intelligent completions have expanded the application of retrofit systems. These technologies support more selective reservoir management and help maximise recovery from mature assets. In addition to increasing production from the existing well, retrofit multilaterals can also reduce water handling requirements, providing broader field-level production benefits.

Conclusion

As operators prioritise brownfield optimisation and infrastructure efficiency, multilateral technologies are an important part of mature field redevelopment. Slot recovery provides maximum flexibility for complete well redesign and is effective for depleted or mechanically compromised wells where updated reservoir understanding supports a new optimised architecture. Retrofit multilaterals offer a lower-cost redevelopment alternative that preserves existing production while increasing access to bypassed reserves. Together, these approaches help operators maximise recovery from existing infrastructure while reducing the need for additional well slots, new facilities, and major surface modifications. Advances in multilateral junction systems and intelligent completions continue to improve reliability, production control, and deployment flexibility in mature onshore and offshore assets. As redevelopment priorities shift toward field-life extension and capital efficiency, slot recovery and retrofit multilaterals can help operators unlock bypassed reserves, maximise recovery, and sustain long-term production from mature assets.

About the author Tom Fanchin Tom Fanchin serves as Halliburton’s Senior Product Champion for Multilateral Technology. He joined Halliburton in 2012 as an Associate Technical Professional in Odessa, Texas, and subsequently advanced through a series of global technical, business development, and advisory roles supporting liner systems and multilateral technologies. In his current role, Tom serves as Halliburton’s global subject matter expert for multilateral technology, providing technical and application expertise to customers and internal stakeholders worldwide. He supports the development and deployment of multilateral completion technologies and leads global portfolio and business development initiatives. He has co-authored ten technical papers and actively contributes to industry knowledge sharing and professional development through technical mentorship, technical publications, and content development. Tom holds a Bachelor of Science in Mechanical Engineering from the University of Southern California and a Graduate Certificate in Subsea Engineering from the University of Houston.

Bibliography

1. KELSEY, M., RAAHOLT, M., EINERVOLL, O., NAFIKOV, R., and AMBLE, S. 2021. Extending Production Life of Mature Fields in the North Sea with Multilateral Technology. Presented at the SPE Annual Technical Conference and Exhibition, Dubai, UAE, 21–23 September 2021. SPE-205874-MS. https://doi. org/10.2118/205874-MS. 2. KELSEY, M., FANCHIN, T., VAN DER VEEN, S., and NESHEIM, M.H. 2022. Multilateral Re-Entry Technology Compounding Benefits and Extending Production Life Past Two Decades. Presented at the Offshore Technology Conference, Houston, Texas, USA, 2–5 May 2022. OTC-31855-MS. https://doi. org/10.4043/31855-MS.

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Craig Morrison, DMO Service Operations Manager, Dräger, considers gas detection and monitoring upgrades at a North Sea HP/HT platform. ffshore oil and gas assets are, by their very nature, high-risk environments where reliable gas detection equipment is critical to protecting personnel and maintaining safe, uninterrupted operations. This is particularly true for high pressure, high temperature (HP/HT) reservoirs, where elevated process conditions demand safety systems that are dependable, fully supported, and capable of evolving alongside the asset.

The platform in this case study is a normally manned, integrated Process, Utilities, and Quarters (PUQ) installation, bridge-linked to a dedicated wellhead platform. Operating in a HP/HT reservoir environment, the asset presents a demanding set of conditions for any gas detection system: temperature extremes, moisture, potential for explosive atmospheres, and the everpresent requirement for confined space and tank entry work.

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As part of its ongoing commitment to safety and operational integrity, the operator initiated a review of its gas detection capability across the asset, ultimately selecting Dräger to deliver a modern, integrated solution.

The challenge

The primary driver for change was equipment obsolescence. The existing gas detection system had reached a point where replacement timelines from the incumbent supplier were unclear, and the availability of spare parts was sparse. The operator had been advised that support would be available for a ‘limited time’ only,

Figure 1. X-am 8000.

Figure 2. X-Dock.

Figure 3. X-Zone.

26 | Oilfield Technology September/October 2026

without any firm commitment on how long that window would remain open. For a safety-critical asset with no tolerance for unmonitored downtime, that uncertainty was unacceptable. After-sales support had also become a recurring problem. Access to servicing, spare parts and maintenance from the existing supplier was inconsistent. Offshore assets depend on responsive technical support – any gap in that chain introduces risk. The absence of a locally based support function compounded the issue, increasing the time and cost of any intervention. With safety-critical equipment approaching end-of-life and no clear upgrade pathway from the existing supplier, the operator began exploring alternatives. Conversations with other assets within its portfolio revealed that Dräger technology was already in operation across the wider fleet, with consistently positive feedback on performance and reliability. Fleet alignment and lessons from those earlier transitions carried significant weight in shaping what came next.

The solution

Following evaluation, the operator selected Dräger to deliver a comprehensive gas detection and monitoring solution, aligned with both the immediate requirements of the asset and the longer-term direction of the operator’s portfolio. X-am 5600 multi-gas detector The X-am 5600 forms the backbone of personal gas monitoring across the asset. One of the most compact multi-gas detectors available, it can simultaneously monitor up to six gases through a combination of infrared and electrochemical sensors, including combustible gases, oxygen, and a range of toxic gases such as carbon monoxide and hydrogen sulfide. Built to IP67 standards, it remains fully functional in wet and dusty conditions, and its integrated rubber boot provides additional protection against impact and vibration. A key practical advantage is Dräger’s infrared sensor technology which offers a lifespan of up to eight years and requires calibration only once every 12 months, significantly reducing the maintenance burden compared with standard electrochemical alternatives. A further differentiator is the X-am 5600’s dual-use capability: the same device used as a personal monitor

can be inserted directly into an X-zone area monitoring unit, creating a single, interoperable piece of equipment that serves multiple work scopes without the need for separate hardware. X-am 8000 specialist gas detector For more specialist applications, the X-am 8000 extends the detection capability of the fleet. Configured with a high-performance photoionisation detection (PID) sensor, the device supports benzene-specific detection and hydrocarbon monitoring in nitrogen-rich environments, making it well suited to tank purging operations and confined space work where standard combustible gas sensors are not appropriate. The X-am 8000 features inductive charging, which eliminates the corrosion and contact degradation issues associated with conventional charging cradles, an important consideration for offshore environments. It can also accommodate pump hoses of up to 45 m, allowing pre-entry monitoring of confined spaces from a safe distance. X-zone area monitoring The X-zone units extend gas detection beyond the individual, creating wireless safety perimeters across defined work areas. Up to 25 units can be interconnected automatically to form a fenceline covering large operational areas, with a wireless range of up to 100 m between devices. When any unit in the network detects a gas alarm, the signal is transmitted across all connected units simultaneously, providing site-wide situational awareness rather than isolated point detection. Visual indication is provided by a 360º illuminated LED ring: green when conditions are safe, red when gas is present. With up to 120 h of continuous operation from a single charge, the units are suited to extended shutdown and turnaround activities where temporary monitoring perimeters need to remain in place for several days. X-dock automated testing and calibration The X-dock system automates the bump testing, calibration, and record management processes that would otherwise require manual intervention for every device in the fleet. Multiple instruments can be tested simultaneously or independently, and the system’s reduced gas flow (approximately 40% lower than standard rates) keeps test gas consumption, and therefore operating costs, to a minimum. Data from each test is captured and stored via the X-dock Manager software, creating a traceable record of device readiness and compliance that supports audit requirements and regulatory obligations. Devices are logged using barcodes or integrated RFID transponders, providing the operator with a clear and current picture of fleet status at all times. From initial engagement to delivery, the project progressed over a two-to-three-month period. Dräger provided dedicated account management throughout, including a designated administrator who coordinated equipment specification and ensured delivery to the asset was both timely and complete. Ongoing support includes onboarding assistance and training for

personnel, ensuring confidence and competence across the workforce.

Key outcomes

Trials and evaluations conducted across other assets in the operator’s portfolio informed the decision. The expected benefits are now being realised as the solution is rolled out: Resolution of equipment obsolescence risk, with a clear and supported upgrade pathway replacing the uncertainty of the previous system. Reduced maintenance requirements compared with legacy equipment, supported by infrared sensor technology with longer service intervals and extended operational lifespans. Greater equipment versatility, with the X-am 5600 serving as both personal monitor and area monitor component, reducing the total number of device types required across the asset. Improved lifecycle value despite higher initial capital outlay, with lower long-term ownership costs driven by reduced calibration frequency, longer sensor life and decreased reliance on consumables. Fleet alignment across the operator’s wider portfolio, simplifying procurement, servicing and training requirements. Automated device management through the X-dock system, reducing manual testing workload and ensuring instruments are consistently deploymentready. Enhanced situational awareness during dynamic work scopes such as shutdowns and turnarounds, through wireless X-zone fenceline monitoring that extends protection beyond the individual. Traceable compliance data generated automatically, strengthening audit readiness and supporting ongoing regulatory obligations.

Ì Ì Ì Ì Ì Ì Ì Ì

Conclusion

By transitioning to Dräger’s integrated gas detection and monitoring solution, the operator has established a safety framework with a clear long-term support structure behind it. The move resolves the immediate risk posed by ageing, unsupported equipment, while the choice of an interconnected, interoperable system means the asset is well positioned to meet evolving offshore safety standards and digitalisation requirements. The X-dock system, in particular, marks a shift in how gas detection is managed: away from manual, reactive maintenance cycles and towards automated, data-driven fleet oversight. Combined with the wireless situational awareness provided by X-zone and the specialist detection capability of the X-am 8000, the solution treats gas detection as a proactive risk management tool rather than a basic compliance control. For the operator, the decision also reflects a broader portfolio strategy. Aligning gas detection technology across multiple assets simplifies procurement, reduces the training burden on personnel moving between installations, and creates a common platform for fleet management and performance reporting. The experience of peer assets in making the transition to Dräger was a significant factor in the decision, and the results to date suggest that confidence was well placed. September/October 2026 Oilfield Technology | 27

28 |

Dr HyunJin Kim, Senior Vice President, Head of Technology, Hanwha Ocean EPU, and Amir Samoiloff, CEO, SIGA, comment on protecting the future of autonomous offshore operations.

A shift to an autonomous operating model

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into automated workflows and predictive logic that can be scaled across the entire fleet.

this foothold, attackers can move from simple network intrusion to a stage of calculated, long-term manipulation.

The evolving risk landscape

Strategic persistence and ICS spoofing

The transition to autonomous operations does not create new categories of risk so much as it intensifies existing ones. These are the two primary paths to an FPSO cyberattack:

A further complicated factor is that deep-pocketed adversaries have shifted from immediate sabotage to long-term persistence. CISA and the FBI (Advisory AA24-038A) have warned that state-sponsored actors, such as Volt Typhoon, The network path (increased digitalisation) are ‘pre-positioning’ in critical infrastructure to exert leverage To enable remote control, systems that were once during future geopolitical conflicts. Their objective is to physically isolated need to be integrated into maintain quiet access, enabling them to exert strategic interconnected control networks. This constant leverage or launch disruptive strikes during future geopolitical bi-directional data flow creates a ‘direct highway’ for conflicts. attackers to move laterally from a corporate IT breach The risk is that attackers hijack the communication into the vessel’s critical OT and safety systems. between field sensors embedded within FPSO equipment The hardware path (supply chain) and the onshore remote control centre. If Industrial Control This is the industry’s most acute vulnerability. According System (ICS) readings are spoofed (manipulating values sent to the KPMG 2024 Energy Cyber Report, supply chain to onshore operators), it blinds them to the reality of the asset. weaknesses now account for 45% of security incidents This allows adversaries to change physical ballast or pressure in the US energy sector, nearly double the global logic on the vessel while operators are under the illusion that average. the system is operating within normal parameters. These entry points for adversaries to embed themselves A critical exacerbating factor in this landscape is the rise of deeply within the asset’s control architecture. By gaining Generative AI and AI Agents. Unlike traditional malware, which follows a static script, AI agents are autonomous programs capable of Table 1. IOC value dimensions and KPIs reasoning, pivoting, and executing complex, multi-step attacks without Value dimension Key performance indicator (KPI) What improves human intervention. This technology acts as a force multiplier for hostile Dramatically reduces time to detect Mean time to detect (MTTD) and Detection and response and contain threats via cyberactors in two primary ways. mean time to respond (MTTR)

physical correlation.

Spoofing detection rate

Identifies manipulated or falsified operational states by comparing command logic to physical response.

Operational safety

Avoided escalation events

Lowers unplanned shutdown risk by catching abnormal manipulations before they trigger protective trips (SIS/ESD).

SOC efficiency

Alert triage time

AI narratives reduce operator cognitive burden and the number of alerts per incident.

Fleet scalability

Deployment lead time

Standardised architecture allows for high configuration reuse across multiple FPSO assets.

Signal trust

Generative AI and autonomous AI agents

AI agents are autonomous programs that use the reasoning capabilities of Generative AI to plan and carry out complex tasks on their own. Unlike traditional malware that follows a rigid, step-by-step script, these agents are given a goal (e.g. ‘disable the ballast system’) and are empowered to figure out the best way to achieve it. Automated reconnaissance and discovery AI agents can rapidly ingest and analyse proprietary industrial code to identify logic flaws in safety protocols. This automates the creative problem-solving and deep reconnaissance that previously required months of manual effort by elite engineering teams.

Industrialised, multi-fleet strikes These agents allow a single adversary to launch ‘hands-onkeyboard’ style intrusions across an entire fleet simultaneously. By mimicking the adaptive behavior of a human hacker at machine scale,

Figure 1. FPSO multi-level OT security architecture.

30 | Oilfield Technology September/October 2026

AI agents can bypass traditional defences and exploit vulnerabilities

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at a speed that vastly outpaces human-led defensive responses.

In the context of an NUI, this means an AI agent can autonomously discover a path through a supply chain vulnerability, move laterally into the OT network, and begin spoofing ICS readings before an onshore security team can even register the initial breach.

The key to FPSO hardening: multi-level verification

On an unmanned FPSO, the critical danger is from time-todiscovery. Because there are no personnel onboard to witness mechanical strain, hear abnormal pump vibrations, or verify physical gauges, an attack can escalate into a catastrophic event before it is detected onshore. Whether a threat originates from a top-down network breach or a bottom-up supply chain exploit, the lack of a ‘human firewall’ creates a profound operational blind spot. To close the detection gap on an unmanned FPSO, security must move beyond the network edge and encompass every layer of the industrial environment. This requires a Multi-Level OT Cybersecurity strategy that provides visibility from the top-level software down to the physical process.

Integrated OT Cybersecurity (IOC) reference architecture for FPSO

A unified defence monitors both the attack vector (how the adversary entered) and the attack expression (the physical result of the attack) across all operational layers. The IOC architecture provides a consolidated operational view across offshore and onshore domains. Onboard, the system monitors Level 0 physical signals (electrical signatures) alongside Level 1 - 3 networks, maintaining strict segregation of safety-critical systems (SIS/F&G). This process and security data is securely transmitted via DMZ or data diodes to the onshore Remote Operations Centre (ROC), where AI-assisted agents correlate the information to generate event narratives and automated response playbooks. The core of this strategy is the continuous comparison of these layers. By identifying discrepancies between digital commands at the top and raw electrical signals at the bottom, the system exposes manipulation in real-time. This independent verification allows operators to see the truth even when their control screens have been compromised.

Key differentiators of IOC for offshore FPSO assets

Unlike conventional cybersecurity, the IOC solution is engineered specifically for the high-consequence, unmanned offshore environment: Physical process-anchored verification: uses Level 0 electrical and mechanical behaviours as a tamper-proof ‘ground truth’ to detect manipulated or spoofed control logic that traditional software-only security would miss. Unified offshore-onshore context: breaks down silos by integrating FPSO onboard monitoring with onshore Security Operations Centre (SOC) workflows under a single, cohesive operational model. AI-assisted narrative and decision support: moves beyond simple alerts by using AI to transform fragmented data into human-readable narratives and actionable playbooks for faster incident response. FPSO-specific deployment: utilises passive, non-intrusive monitoring designed to satisfy strict offshore class

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32 | Oilfield Technology September/October 2026

requirements, Management of Change (MOC) processes, and the technical constraints of brownfield assets.

Value proposition and performance indicators

To ensure objective evaluation, the IOC solution is assessed via measurable KPIs that reflect both cybersecurity effectiveness and operational impact.

AI defensive agents and automated playbooks

The rise of autonomous AI Agents represents a profound escalation in risk, as these tools can reason, adapt, and act within the ICS without human instruction. To counter an adversary that ‘thinks’, defenders must move beyond static security rules and integrate agentic AI into the heart of the offshore security architecture. At a strategic level, agentic AI transforms defence by moving from passive monitoring to autonomous reasoning. Unlike traditional software that simply flags a high temperature, a defensive AI agent analyses the ‘intent’ of the system. It crossreferences the network command, the current mission profile, and the raw Level 0 electrical signals to determine if a deviation is a mechanical fault or a deliberate manipulation. This reasoning capability allows the AI to build a realtime event narrative – a live, evolving timeline of the incident that provides operators with clear situational awareness of a potential cyber event as it unfolds. When the AI agent detects a discrepancy between the digital command and the physical reality at Level 0, it autonomously generates actionable recommendations. This is where the AI turns its reasoning into an automated playbook. Instead of a generic alarm, the operator receives a plain-language, step-by-step response sequence – such as ‘isolate the affected cargo pump’ or ‘switch to safe mode’ – to contain the threat before it escalates into physical damage. By anchoring defence in raw Level 0 signals, these insights remain accurate even if HMI displays are falsified. This allows onshore operators to act with evidence-based confidence during critical moments. By bridging the gap between digital data and physical truth, the autonomous FPSO can move from reactive firefighting to decisive control, catching attacks at the moment of execution.

Conclusion: securing the future of offshore energy

The transition to autonomous operations is necessary for the FPSO industry’s economic and operational resilience. However, removing the human presence requires a fundamental shift in the approach to cybersecurity. Because a remote operator can no longer physically ‘walk the line’ to verify a valve’s status, the traditional ‘human firewall’ has vanished. To ensure safety, a Multi-Level OT strategy must be implemented where the ‘truth’ is never allowed to reside in a single software layer. Ultimately, a hardened OT strategy is about buying back time. In an unmanned environment, the window between a cyber-incident and a catastrophic physical failure is dangerously narrow. By using AI to cross-verify operational commands against mechanical behaviour (such as checking if a reported pressure drop) aligns with real-world flow rates that operators can detect an attack the moment it attempts to manipulate the vessel’s logic. For the future of autonomous offshore production, resilience is no longer just a digital checkbox; it is a physical necessity.

nnovation in oilfield chemistry rarely starts with a blank sheet. More often, it begins with a simple but persistent question: Can we do this better?

Rethinking H2S scavenging: from industry standard to next-generation innovation Can we do this better? For hydrogen sulfide (H2S) management, the industry has relied on conventional scavenger chemistries for decades, most notably triazine-based systems such as MEA- triazine. This

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product is typically synthesised by reacting monoethanolamine with formaldehyde, forming a reactive structure capable of binding H2S efficiently. It has become the industry standard due to its robust performance, wide availability, and ease of application across a broad range of production environments. However, its reaction mechanism proceeds stepwise, which can result in comparatively slow kinetics under certain operating conditions, particularly in systems with limited mixing, short residence times, or high water cut. In addition, MEA-triazine introduces significant alkalinity to the system, which can promote inorganic scaling and impact downstream operations. As a water-based formulation, it also presents logistical challenges in terms of transport, storage, and cost efficiency. A further well-recognised limitation is the formation of polymeric solid by-products. These can accumulate within the production system, contributing to fouling, plugging, and increased maintenance requirements, factors that continue to present operational challenges in modern oil and gas production. What alternatives has the industry explored? In response to these limitations, alternative chemistries have emerged over the past decade, including oxazolidinebased systems such as methylenebisoxazolidine (MBO). These chemistries were specifically developed to address the shortcomings of traditional triazines, offering higher theoretical scavenging capacity, lower water content, which translates into a more efficient logistical footprint and improved solubility across both oil and aqueous phases. In many applications, MBO-based scavengers have demonstrated enhanced thermal stability, lower alkalinity, and a reduced tendency to form problematic polymeric deposits. These characteristics make them an attractive option, particularly in more demanding or high-performance operating environments where conventional solutions may struggle. Why is further improvement still needed? Nevertheless, while these next-generation chemistries represent a significant step forward, they are not without their own limitations. In certain applications, reaction kinetics can still become a critical factor, particularly in systems with short residence times or challenging flow conditions, impacting overall treatment efficiency. In addition, cost-effectiveness remains a key consideration and furthermore, although reduced compared to conventional systems, the moderate alkalinity of these formulations may still contribute to scaling risks in more sensitive production environments. Why is now the time for a step change? As production systems become increasingly complex, characterised by shorter residence times, multiphase flow, and tighter operational constraints, the need for a step change in scavenger performance has become ever more Table 1. Alkalinity profile Alkalinity mg/l CaCO3 *active ingredient

100 ppmw*

500 ppmw*

1000 ppmw*

stabicor® S 500

180

360

MEA-Triazine

360

>700

34 | Oilfield Technology September/October 2026

apparent. Rather than relying on incremental improvements, the industry is now shifting toward fundamentally rethinking H2S scavenging chemistry to deliver faster, cleaner, and more efficient performance under real-world operating conditions. Where does true innovation begin? It was against this backdrop that the idea for a new generation of scavenger chemistry began to take shape, starting as a concept sketched on paper, yet driven by a clear ambition for innovation. The objective was not merely to match existing technologies, but to redefine performance standards: delivering significantly improved efficiency, faster reaction rates, and a more favourable operational profile, all while aligning with increasingly stringent environmental and regulatory expectations. How was the innovation developed? What followed was a structured, yet strongly innovation-driven development journey. It began with targeted molecular design and laboratory synthesis, deliberately challenging conventional approaches while remaining close enough to established H2S scavenging pathways to avoid introducing unnecessary complexity or unintended side effects. This balanced approach ensured that innovation was both meaningful and practical, delivering performance improvements without compromising reliability in field applications. What makes the new approach different? Building on the foundation of oxazolidine chemistry, the team engineered a novel chemical system designed to push the boundaries of H2S- scavenger performance. The result was a next-generation chemistry combining rapid reaction kinetics, enhanced H2S removal capacity, and a reduced tendency toward operational side effects such as scaling and fouling, ultimately bridging the gap between proven chemistry and true innovation. Early laboratory-scale synthesis quickly demonstrated the promise of the new technology, the stabicor® S 500. It exhibited strong reactivity towards H2S, combining high scavenging efficiency with rapid reaction kinetics, while maintaining a lower alkalinity profile and excellent thermal stability. Equally important, the formulation was designed with practical field application in mind. It offers high concentration levels, reducing logistical footprint and associated costs, while maintaining favourable viscosity and pumpability. At the same time, it remains stable, versatile, and fully compatible with multiphase production systems, ensuring seamless integration into existing operations. Can laboratory success translate into field performance? However, as with any oilfield innovation, laboratory success alone is not enough. The real challenge lies in translating controlled results into complex, real-world operating environments.

From theory to proof: demonstrating performance in the laboratory With the concept validated, the next step was to rigorously test the formulation under conditions representative of real oilfield operations. One of the key differentiators identified early in the evaluation was the alkalinity profile. Conventional scavengers

are known to significantly increase system pH, often triggering inorganic scaling and negatively impacting production facilities. In contrast, the new chemistry demonstrated a markedly lower alkalinity contribution, reduced by at least a factor of two, as illustrated in Table 1, thereby minimising the risk of deposits forming in pipelines, valves, and process equipment. Equally critical was the evaluation of H2S removal efficiency, defined by two parameters: how much H2S can be removed, and how quickly the reaction occurs.

advanced analytical techniques such as Raman spectroscopy were employed. These investigations confirmed that the reaction pathway rapidly progresses to stable end products, limiting the build-up of intermediate species typically associated with operational issues. Taken together, the laboratory findings clearly demonstrated that this technology represents more than an incremental improvement, it marks a meaningful step forward in H2S scavenging performance.

Is the new innovation delivering fast kinetics? In a first test H2S performance kinetics were evaluated using IP570 in a multiphase oil/brine system. Results showed that stabicor® S 500 delivered significantly faster reaction kinetics than MEA-triazine, achieving up to 50 - 61% H2S reduction within five minutes at low dosage ratios (2:1 - 3:1). In contrast, MEA-triazine required much higher dosages (5:1 - 7:1) yet achieved only 25 - 33% reduction, highlighting the superior efficiency of the new technology, particularly under short contact time conditions.

While laboratory data provides confidence, the ultimate validation of any oilfield technology comes in the field. For this innovation, that test came in one of the most challenging environments: offshore production systems in the North Sea.

Outstanding chemical H2S- scavenging capacity? As illustrated in Figure 1, controlled contact tower tests simulating field conditions demonstrated a clear step change in performance and confirmed the high H2S scavenging capacity of the new technology. It consistently maintained H2S concentrations below industry threshold levels for significantly longer durations than conventional solutions. Notably, the time to breakthrough, when H2S levels exceed acceptable limits, was extended by more than three times compared to MEA‑triazine. Another key area of focus was by-product behaviour, which is often a major source of operational challenges. Conventional scavengers can generate insoluble solids that accumulate within the system, leading to fouling, increased pressure drop, and higher maintenance demands. The new formulation was therefore designed to mitigate these risks by favouring the formation of more manageable and, under certain conditions, soluble reaction products. To gain deeper insight into the underlying mechanisms,

The real test: proving performance offshore

Figure 1. H2S Breakthrough test, continuous H2S bubbling through a scavenger solution, KPI stay below

10 ppm as long as possible.

Figure 2. First field trial: stabicor® S 500 enabled an approximately 65% reduction in MEA-triazine

consumption while maintaining export gas H2S within specification.

Figure 3. Impact of scavenger dosage on H2S removal performance and export oil quality. September/October 2026 Oilfield Technology | 35

The selected field application represented a particularly demanding scenario. The system was characterised by extremely short residence times, just 2 - 3 seconds between chemical injection and the cooling stage. Under such constraints, conventional scavengers typically require significantly higher dosages to compensate for slower reaction kinetics. In addition, the operator faced ongoing challenges, including fouling, pressure instability, and elevated chemical consumption. The objective was therefore not only to control H2S effectively, but to do so in a more efficient and reliable manner, with reduced operational side effects. Three field trials with stabicor® S 500 were conducted over a two-year period. The first focused on demonstrating high reaction kinetics and, consequently, reduced chemical consumption. The second evaluated the impact on overall system performance. The third confirmed stable operation with no adverse effects during continuous injection over a three-day period. First field trial: turning laboratory promise into field performance First trial: stabicor® S 500 was co-injected alongside the incumbent H2S scavenger to evaluate the potential for reducing incumbent chemical consumption while maintaining treatment performance. One of the most significant outcomes of the trial was a 60 - 65% reduction in incumbent scavenger demand, while consistently keeping H2S concentrations within the required specification limits. This substantial decrease in chemical usage translated directly into both operational efficiencies and economic savings, demonstrating the effectiveness of the combined treatment approach. More importantly, the field data confirmed the laboratory findings: the chemistry reacts rapidly, even under extremely limited contact time. This fast kinetics profile enabled effective H2S removal in conditions where conventional systems typically require higher dosages and may still struggle to meet targets. Notably, no adverse operational changes were observed during this initial trial. Second field trial: unravelling reaction pathways with innovative field-deployable Raman technology In the second trial, the focus shifted to understanding reaction pathways and by-product formation under live operating conditions. Using a combination of advanced analytical techniques, including field-deployable Raman spectroscopy, the team confirmed that the dominant reaction products were stable dithiazine species, fully consistent with laboratory findings. This stability is attributed to the chemistry’s ability to rapidly convert reactive intermediates into final products, thereby reducing the likelihood of partial reactions that can lead to deposit formation. This confirmation is particularly significant, as it demonstrates that the chemistry behaves predictably not only under controlled laboratory conditions, but also in complex, real-world operating environments. Third field trial: three-fold reduction in chemical consumption with stable operation and system clean-up A third field trial evaluated continuous injection over a three-day period under both standard and elevated dosage 36 | Oilfield Technology September/October 2026

conditions. The results demonstrated a substantial reduction in incumbent MEA-triazine consumption – from approximately 6500 L/d to 2300 L/d of stabicor® S 500 – equivalent to a three-fold decrease in chemical usage, while maintaining stable system performance throughout. No adverse impact on operational parameters was observed, with consistently stable pressure profiles across the system. In addition, a progressive clean-up of previously accumulated H2S reaction by-products was noted throughout the trial. A particularly beneficial observation was the behaviour of the spent scavenger reaction products: instead of forming problematic solid dithiazine (DTZ) deposits, a liquid DTZ phase was observed in the spent samples. This behaviour significantly reduces the risk of fouling and plugging, particularly at critical locations such as cooler inlets and associated process equipment. The clean-up effect was further accompanied by improved water quality, reflected by a clear reduction in oil-in-water levels, as well as positive downstream benefits, including enhanced glycol quality.

Looking ahead: driving innovation, efficiency, and sustainability in H2S management The development and successful field validation of this next-generation H2S scavenging technology demonstrate what can be achieved when innovation is firmly grounded in real operational needs. From initial concept through laboratory validation to offshore deployment, this journey reflects a clear objective: delivering measurable improvements in performance, efficiency, and overall system integrity. Field results have confirmed several key advantages: Accelerated reaction kinetics and higher scavenging capacity, enabling significantly reduced chemical consumption and associated logistical benefits. Lower alkalinity impact, with consistently reduced pH profiles observed across all trials. Improved operational stability, with no evidence of fouling or pressure fluctuations. Enhanced environmental alignment, driven by lower overall chemical loading and improved biodegradability characteristics.

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For operators, these benefits extend well beyond effective H2S removal. They open the door to optimising entire production systems, reducing costs, improving reliability, and supporting sustainability targets. While the results are highly promising, continued evaluation remains essential. Further work will focus on long-term field performance, interactions with other production chemicals, and comprehensive environmental impact assessments across a broader range of operating conditions. Nonetheless, the findings to date clearly illustrate that rethinking core chemistry can unlock substantial value. In an industry facing increasing technical complexity and regulatory pressure, such innovations highlight that even well-established processes can be transformed – starting from a simple idea and ultimately delivering tangible impact where it matters most: in the field.

Brent Halldorson, US Business Development Director, LiqTech International Inc., considers solutions for when produced water stops behaving and treatment still has to work. roduced water exposes the fragility of treatment systems built around steady-state assumptions. As variability, emissions constraints and reuse ambitions collide, this article argues that resilience under upset conditions, not optimisation on good days, now determines whether produced water can be treated as a controllable resource rather than a liability. Produced water has a habit of exposing uncomfortable truths. On paper, it looks manageable. Volumes can be forecast, chemistries characterised, treatment trains designed. In practice, it behaves less like a stable utility stream and more like a moving target. Oil concentrations swing without warning. Temperatures shift with seasons and operations. Biological activity appears where it was not expected. Chemistry drifts just far enough to upset processes that were never designed for that level of variability. When this happens, treatment systems are not tested at their best. They are tested at their weakest. For decades, the industry has tolerated this fragility because the alternatives were limited. Produced water was treated primarily as a waste stream, something to be stabilised enough for disposal, reinjection, or basic reuse. If systems struggled during upset conditions, operators worked around it. Tanks overflowed. Equipment was taken offline. Chemistry was adjusted by hand. Downtime was absorbed as an operational cost. That model is now under strain, not because produced water volumes are new, but because expectations around reliability, emissions, reuse, and economics have changed. Across oil and gas operations, produced water is no longer judged solely by whether it can be disposed of. It is increasingly evaluated by whether it can be controlled. That distinction matters. Control means predictable performance under non-ideal conditions. It means treatment output that does not collapse when inlet conditions deteriorate. It

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means systems that can absorb oil spikes, temperature swings, and variability without cascading failure. In short, it means resilience, not optimisation.

The real challenge operators underestimate

When operators talk about produced water challenges, the conversation often gravitates toward salinity, disposal capacity, or long-term reuse ambitions. These are real issues, but they tend to overshadow a more immediate and underestimated problem: instability. Produced water rarely fails slowly. It fails abruptly. An upstream upset can send oil concentrations surging through a system in minutes. A temperature drop can change fluid behaviour overnight. A biological shift can quietly degrade performance until it becomes impossible to ignore. Conventional treatment technologies struggle in these moments because they were never designed to behave deterministically under variable feed conditions. Dissolved air flotation (DAF) systems, still widely used after decades of service, are a case in point. They are attractive because they are simple and inexpensive. They also rely on a delicate balance of chemistry (polymer, flocculant, coagulant), hydraulics, bubble size, particle charge, and air dispersion. When that balance is disturbed, output quality changes immediately. Oil spikes pass through, solids removal degrades, and downstream equipment is exposed. The consequences extend beyond water quality. Oil that escapes treatment is oil that never reaches a sales stream. It contaminates reinjection wells, damages reservoirs, and compromises subsequent treatment stages. When upset

Figure 1. QureFlow water filtration system.

Figure 2. Membrane housing.

Figure 3. QureFlow OnSite – oil and gas.

38 | Oilfield Technology September/October 2026

conditions overwhelm open systems, operators are often left with few options other than to shut down and manually intervene. Tanks must be emptied. Oil must be skimmed. Residual sludge must be removed. Personnel are sent in with hoses, shovels, and protective equipment. Downtime stretches from hours into days. None of this appears in laboratory performance curves, but all of it appears in operating reality.

Why resilience now matters more than efficiency

For years, produced water treatment has been optimised around steady-state assumptions. Systems were designed to perform well under nominal conditions, with efficiency gains measured in incremental improvements. That approach is increasingly misaligned with how operations actually run. In the field, peak efficiency is less valuable than consistent performance. Operators do not need a system that performs brilliantly on good days and collapses on bad ones. They need one that behaves predictably when conditions inevitably deteriorate. This is where resilience becomes the defining requirement. A resilient system does not rely on open tanks that amplify variability. It does not depend on finely tuned chemical balances that must be constantly adjusted. It does not require frequent human intervention to remain stable. Instead, it provides an absolute barrier between inlet volatility and outlet quality. It absorbs shocks rather than transmitting them downstream. That distinction became clear during a six-month field trial carried out through the winter in the DJ Basin, where produced water conditions are among the most volatile operators encounter. The trial centred on an enclosed ceramic crossflow ultrafiltration system deployed directly on live produced water streams, upstream of any desalination or reuse process. Rather than operating under controlled test conditions, the unit was deliberately exposed to real operational variability, including seasonal temperature swings, the introduction of high temperature frac flowback, changing upstream chemistry, and repeated oil spikes linked to routine disruption of upstream oilwater separation systems. The objective was not to optimise peak efficiency, but to observe how a single-step, enclosed treatment system behaved when inlet conditions deteriorated. During periods of low ambient temperatures, fluctuating feed composition, and episodic oil surges, stable output mattered more than marginal gains on paper. What operators noticed was not how the system performed when everything was working well, but how little changed when things went wrong. Output quality remained consistent, pressure and flow behaviour remained within predictable ranges, and upset events did not cascade through the treatment train.

Enclosure as a functional necessity, not a design choice

One of the most persistent weaknesses in conventional produced water treatment is its reliance on open processes. Open tanks expose oily water to the environment, allow volatile compounds to escape, introduce dust/bacteria, and magnify the impact of feed variability. They also create compliance risks in regions where emissions are regulated tightly. In jurisdictions such as Colorado and New Mexico, exceeding emission thresholds can halt operations entirely. In other regions, emissions may be tolerated, but the operational risks remain.

Enclosed treatment is often framed as a clear environmental and/or regulatory preference. In practice, it is a functional necessity for resilient operation. Enclosure allows intensive internal hydraulics that simply cannot be achieved in open systems. It enables aggressive fouling management without releasing contaminants into the atmosphere. It reduces the footprint of treatment infrastructure while eliminating intermediate tanks that become failure points during upset conditions. Ceramic crossflow ultrafiltration operates on this principle by necessity rather than intention. The technology requires a closed loop to sustain the velocities needed to keep membrane surfaces clean. That same closed loop delivers operational benefits that extend well beyond filtration. Oil spikes are contained. Emissions are eliminated. Cleaning processes are internal and controlled. There is no overflow event to manage, no tank to empty, no open surface to foul. The risk of operator exposure to hydrogen sulphide (H₂S) is also reduced.

Why single step matters more than incremental improvement

Produced water treatment trains have historically evolved by accretion. A flotation unit is added to handle bulk oil and solids. A media filter is added to polish fine solids. A nutshell filter is installed downstream to trap organics carryover and protect sensitive equipment. Each step solves a problem, but each step also introduces additional cost, new complexity, new waste streams, and new failure modes. Backwash water must be treated again. Intermediate storage becomes necessary. Control logic grows increasingly fragile. Leaks, spills and overflows become increasingly more likely. Eliminating intermediate steps does more than simplify a process diagram. It removes the points where systems typically fail. Single-step oil and solids removal changes the economics of reliability. There are fewer assets to maintain, fewer interfaces to manage, and fewer opportunities for upset conditions to cascade into downtime. When treatment output remains stable through inlet variability, downstream processes are protected by default rather than contingency. This distinction becomes critical when produced water is no longer destined solely for frac reuse or disposal. Thermal desalination units, reverse osmosis systems, ion exchange resins, and mineral extraction technologies are all intolerant of oil ingress. Even trace amounts will degrade performance or irreparably damage equipment. Conventional pretreatment trains struggle to provide the level of consistency these technologies demand. An absolute barrier at the front of the system changes what becomes possible downstream.

Reframing produced water from liability to controllable stream

The industry increasingly recognises that produced water contains more than waste. It carries water, energy, and valuable minerals. Extracting that value does not require turning every barrel into potable water. In many applications, particularly fracking and internal recycling, clear brine is sufficient. The limiting factor is not desalination. It is the reliable removal of oil and suspended solids. Yet discussion around reuse often jumps straight to desalination because that is where the visible value lies. Freshwater scarcity attracts attention. Thermal desalination plants, advanced osmotic membranes (FO, CFRO, OARO),

ion exchange, solvent extraction and freeze desalination all make compelling headlines. What receives less attention is the operational reality that most reuse strategies fail before desalination even begins, because legacy pretreatment methods cannot deliver consistent inlet quality. When oil and solids removal becomes predictable, reuse strategies become practical rather than aspirational. Recycling water for fracking reduces freshwater demand and transport costs. Reinjection quality improves reservoir performance. Sensitive downstream technologies can be deployed with confidence. In this context, ceramic filtration is not simply an upgrade. It is core infrastructure that aligns treatment capability with upstream variability. Variability upstream is transformed into consistency downstream.

Economics shaped by longevity, not short-term contracts

Cost discussions around produced water treatment often focus narrowly on capital expenditure, making ceramic membrane systems appear expensive when judged against short project timelines. This overlooks the economics of longevity. Designed to operate reliably for many years, ceramic systems reduce cost per barrel treated the longer they run, with warranties that reflect this long-term operating reality. Operational expenditure reinforces this shift in perspective. Conventional systems depend heavily on chemical dosing and manual intervention as feed conditions change, quietly accumulating labour and handling costs. Automated crossflow systems instead trade chemical and labour intensity for energy consumption. While power becomes the primary operating cost, it is predictable, measurable, and stable, turning operational consistency into a financial advantage. Over realistic operating lifetimes, reduced downtime, fewer shutdowns, and consistent output quality outweigh marginal differences in energy use. The greatest value of this approach emerges where regulatory pressure, downstream sensitivity, and operational constraints converge, particularly in emissions-regulated or remote environments where continuous manual oversight is costly or impractical. In these contexts, resilience is not theoretical. Fully automated systems enable consistent performance, support beneficial reuse, and withstand realworld variability, distinguishing solutions that adapt in practice from those that fail when conditions depart from design assumptions.

A different baseline for produced water treatment

Produced water will never behave politely. Variability is inherent, not exceptional. Treatment strategies built around idealised conditions will continue to struggle as performance expectations rise. The shift underway is not toward ever more complex treatment trains, but toward systems that accept variability as a design input rather than a disruption. When oil and solids removal becomes stable under upset conditions, produced water stops being a liability that must be managed and becomes a stream that can be controlled. That change does not happen at the desalination stage. It happens at the front of the process, where resilience is either designed in or designed out. The future of produced water treatment will not be defined by how efficiently systems operate on good days, but by how little changes on bad ones. September/October 2026 Oilfield Technology | 39

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s the world accelerates electrification and decarbonisation, transitional energy sources like natural gas continue to play a role – particularly in powering energy-intensive industries such as big data centres, AI systems and semiconductor plants. It also supports renewable power sources such as wind and solar technologies, facilitates carbon capture and storage, functions as the leading feedstock for hydrogen manufacturing and helps reduce pollution levels compared to other fossil fuels, contributing to cleaner air.1 A managed transition from traditional fossil fuels to renewable energies relies on natural gas as a bridge.2 Given these trends, natural gas production will remain important and relevant for years to come. Oil and gas valve original equipment manufacturers (OEMs) are increasing demand for more information on validated solutions for high-pressure testing at both low and high temperatures. Historically, oil and gas valve OEMs validate their own products. This is costly and time-consuming with tests performed multiple times. Today, valve and subsea system OEMs are turning to their supplier partners for validation and material characterisation services. Before investing the time and money to perform tests in-house or with a third party, they are asking their suppliers to provide evidence that a solution will work the first time.

Validation testing

Validation testing for seals in the oil and gas industry is a critical process to ensure seal integrity and performance in high-pressure and high-temperature environments. Typical oil and gas drilling requirements start at 10 000 psi/69 MPa and temperature ranges from 0 °F to +300 °F (-18 °C to +150 °C.) For gas resources that are harder to reach, pressure requirements may be even greater, near 15 000 psi/103 MPa, while the temperature range can reach beyond +350 °F (+177 °C). Validation testing involves ensuring components meet industry standards and certifications such as American Petroleum Institution (API) 6A. API 6A defines different product specification levels (PSLs) to categorise the quality and performance requirements of equipment. It also outlines temperature and pressure ratings, material requirements and testing and validation criteria. Not all component suppliers are equipped to test according to API 6A specifications.

Material characterisation

Part of validation testing involves material characterisation. Oil and gas valve OEMs should look for component partners like Trelleborg Sealing Solutions that have extensive material characterisation capabilities using dynamic mechanical analysis (DMA) testing. DMA testing is used to assess the mechanical properties of non-metallic materials such as elastomers and polymers commonly used in seals and other components in the oil and gas industry. It helps customers understand how materials will perform under the extreme conditions encountered in real-world applications. Glass transition temperature (Tg) is one important aspect of DMA testing concerning elastomers and other materials used in high-pressure and low-temperature environments. The Tg is the temperature range in which an elastomer changes from a glassy, brittle state to a more flexible, elastomeric state. When an elastomer is in its glassy state, it is frozen and cannot seal effectively. In oil and gas applications, the ability to determine the Tg allows companies to understand their material’s behaviour precisely, which is essential for ensuring the reliability and safety of seals and other components under extreme conditions. Trelleborg uses a highpressure scanning calorimeter (DSC) to measure the glass transition of materials.

Here’s how a DSC measures Tg

Ì Sample preparation: a small sample of the material is placed in the DSC instrument. The sample is typically enclosed in a pan and an empty reference pan is used for comparison. Ì Controlled heating/cooling: the DSC instrument heats or cools the sample at a controlled Ì

rate. As the temperature changes, the instrument measures the heat flow into or out of the sample compared to the reference. Heat flow measurement: during the heating or cooling process, the DSC detects changes in the heat flow associated with the material’s transitions. The glass transition appears as a step change in the heat flow signal. This step change occurs because the material’s heat capacity increases as it transitions from a glassy, brittle state to a more flexible, elastomeric state.

| 41

Ì Data analysis: the DSC software analyses the heat flow Ì

Figure 1. High-temperature/high-pressure valve testing equipment.

data to determine the onset, midpoint and endpoint of the glass transition. The midpoint of the step change is typically reported as the Tg. High-pressure conditions: in high-pressure DSC, the measurements are conducted under elevated pressures, which is particularly useful for applications in the oil and gas industry where materials are subjected to highpressure environments.

Surface and completion (Sub C) testing is another critical process in the oil and gas industry that only the most advanced seal suppliers are equipped to perform. This testing ensures that surface and completion equipment can withstand demanding operating conditions. The tests are typically performed at temperatures ranging from -20 °F to +300 °F (-29 °C to 149 °C) and pressures up to 10 000 psi/69 MPa. Some seals and components need to be tested for cryogenic applications such as LNG transfers between vessels or storage facilities. LNG is natural gas that has been cooled to a liquid state at about -260 °F (-162 °C), reducing its volume by approximately 600 times and making it easier to store and transport. Seals in these environments must be able to withstand temperatures as low as -320 °F (-196 °C) while maintaining their performance. As the demand for natural gas production grows alongside initiatives for decarbonisation and electrification, validated solutions for valves and components are critical to ensure reliability in extreme conditions. The depth and thoroughness needed for oil and gas validation and material characterisation can only be realised by component suppliers like Trelleborg with state-of-the-art facilities and experts with years of experience. Through advanced testing methods, such as DMA and high-pressure DSC, OEMs can gain valuable insights into material performance, ensuring seals reliably meet industry standards and withstand realworld applications.

Hydrogen call out

Figure 2. Scanning electron microscope that can analyse materials to

the nth degree.

Used as fuel, hydrogen is potentially transformative in the battle to reduce emissions from the commercial transportation and industrial sectors. The current and future market needs for hydrogen sealing across the entire value chain – production, transportation and storage, and end use – are very broad, ranging from standard components to highly engineered solutions. Hydrogen’s small molecular size and risk of rapid gas decompression make it difficult to seal and store. Few OEMs have extensive experience in these areas, making an industry leading hydrogen component and sealing partner with proprietary in-house testing capabilities essential. Trelleborg Sealing Solutions has rigs that are approved to test hydrogen. Its facilities offer comprehensive hydrogen-specific standards and validation processes, and their experts can create custom solutions for whatever the customer needs.

References 1. 2.

Figure 3. Trelleborg hydrogen testing lab.

42 | Oilfield Technology September/October 2026

The Role of Gas in the Energy Transition, Michael Stoppard, S&P Global. https:// www.spglobal.com/en/research-insights/special-reports/look-forward/the-roleof-gas-in-the-energy-transition The Role of Natural Gas in the Energy Transition, Emilio Angulo Rodriguez and Ariel Yepez-Garcia, Inter-American Development Bank, November 2020. publications.iadb.org

as regulation in oil wells plays a decisive role in increasing output while preserving mechanical reliability. When pressure is poorly controlled, operators can encounter premature component degradation and marked losses in electric submersible pump performance. The growing technical complexity of contemporary wells – particularly in unconventional, fractured formations – amplifies the difficulty of mitigating

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downhole pressure swings and managing free gas. Addressing these conditions demands a new, more sophisticated adaptive control strategy. Oleum Technology’s System of Integrated Production (SIP) has emerged as a field-validated solution that uses its own proprietary artificial intelligence (AI) and algorithms

Figure 1. SIP’s annular pressure regulator.

to optimise downhole fluid flow. Employed on annular and tubing back pressure valves at the wellhead, SIP-AI minimises the release of free gas so as to increase oil flow in the well. It increases the flow from downhole to the pump, and from the pump to the surface. Unlike traditional methods, SIP’s AI continuously predicts the changing conditions in the well and the flow, and adjusts the pressure accordingly. Both historical and real-time data from the well are used to build the predictive algorithms. Every 60 seconds, the AI evaluates the well’s current operation and predicts the flow changes it sees coming. It then considers the impact that multiple back pressure changes would have. It selects the most appropriate one based on safety, stability, and efficiency criteria. It then sends commands to the two valves to adjust the back pressure so as ensure both smoother well operations and greater production. One of the measurable impacts of SIP is to lower the maintenance costs and prolong the operational lifespan of the pump, and especially ESPs. By seeing the coming of events such as gas blocks and lock, it prevents such events and reduces damage in the pump. More generally, all pumps become more stabilised and efficient under SIP and their oil production increases. The production is proven to increase between 20% and 40% on most wells, and more on those with major instability or production inefficiencies. The only well limits: liquid level at least 250 ft above an ESP and 225 ft above a rod pump; gas-oil ratio (GOR) larger than 7000 ft3/stbn; API between 10 and 45; and, if there is a packer, a way to open it, though SIP’s tubing control by itself works on all wells. The improvements in the pump and the liquid flow are such that they far overcome the relatively minimal back pressure applied by SIP. The result is a new production profile for the well and the greatly increased production. Critically, the higher oil production remains sustained over time, and greater than that of the old decline curve. In this way, SIP not only addresses the gradual decline in well productivity, but also significantly speeds up cumulative oil recovery from the reservoir.

The development and current testing of SIP

Figure 2. SIP’s tubing regulator.

44 | Oilfield Technology September/October 2026

The first version of SIP was developed in closely supervised tests by a team of petroleum engineers, scientists and mathematicians on more than 100 wells across Venezuela and Ecuador. Called SIP-1, it was internationally copyrighted and approved in successful official tests with major oil companies in Colombia and Mexico. The tests were on conventional rod pump and ESP wells with mid-weight and heavy oil. The early version was run from PLC’s at each well. Oleum then tested on light oil and unconventional wells across Louisiana and Texas. It developed a more complex and powerful version called SIP-2 for the particularly complex challenges of fracked wells. Moved to the cloud, the completed SIP-2 has now been successfully tested on more than 20

unconventional ESP wells in the Permian by two major up to a year before declination resumes. When it does, the American oil companies. declination is slower than it was originally. Production has significantly increased on all but one of The well’s new production profile includes extended the wells. The most controlled tests, for example, were of peak periods, smoother and more gradual decline, and one-month bypasses after 3 - 8 months of SIP operation on faster oil recovery from the reservoir. 10 of the wells. Production in them dropped an average of In sum, SIP allows operators to extract more oil more 38% after SIP was temporarily disconnected, proving that quickly over the well’s lifecycle. This is while also reducing SIP had been increasing production by at least that much operational costs – all to the operator’s benefit. before the bypass. On only two of the 10 wells was the increase less than 20%. On four, it was more than 40%. Current well installations Permian Basin (US): five wells testing and five on Thermal shutdowns, meanwhile, were largely standby with two operators; MSA’s with two more. eliminated in all the tests. Mexico: 18 currently operating and 36 on order under SIP’s most extreme impact is on wells suffering gas lock, 150 well contract. which dramatically cuts production. In a six-week Permian Contracts pending after successful tests: Ecuador, test on one such well, SIP freed the pump and increased Colombia, Venezuela production 92%. It ended wild swings in the pump’s Test Commitments: Saudi Arabia, Kuwait, Oman, proportional-integral-derivative (PID) control systems, as Libya. well as frequent thermal shutdowns and stubbornly high pump intake pressure (PIP). Under SIP, PIP, for example, was stabilised at 650 psig. After SIP was disconnected, PIP jumped to 790 psig. The PIP could not be lowered or stabilised by the operator’s re-establishment of PID control. Production plummeted again. On three of the last wells tested – two currently – the newest version of SIP, called SIP-3, was installed. SIP-1 and 2 control a single back pressure valve on the annulus. SIP-3 adds and integrates one on the tubing, adding to pump stability. The results on all three are good. Oleum has patented the ever more complex algorithms of SIP-3. The Permian tests continue as the operators consider major scaling of what Figure 3. SIP impact on ESP operational stability. is a counter-intuitive technology that differs from standard operations to date. In Mexico, meanwhile, a production contract has been issued on 150 wells. The first 18 were installed over the last year. All are conventional wells with rod pumps. Production on them has been running between 30% and 40% higher.

Ì Ì Ì Ì

PIP, PID, and ESP production profile

Looking at ESP operations in particular, SIP’s measurable impact can be seen in its reduction of both PIP and PID. This mostly reflects the gas control achieved by SIP in the annular space, though it is augmented now by the tubing control. The PIP and PID reductions reflect the more mobile, stable liquid flow and reduced gasification, particularly as the threephase solution nears the pump and there is less free gas. It is this stability – seen in temperature, PIP, vibration and current – that contributes to the pump’s operational longevity. It also lowers maintenance costs. Meanwhile, not only does the empowered pump pull and push up more oil, it is proven in the many tests in the Permian and elsewhere to push out the decline curve. It has done so for

Figure 4. Production increase under SIP in a three month Permian test.

Figure 5. Production increase under SIP in a three month Permian test.

September/October 2026 Oilfield Technology | 45

Andy Webster, Senior Director Digital & AI, KBR, explains how physics-informed AI can help engineers interpret asset data, identify anomalies and make more informed operational decisions.

46 |

odern oil and gas assets record a wealth of information. Process historians, equipment sensors, maintenance systems and inspection programmes all generate data, while offshore installations and FPSOs may hold years of operating history. However, not all of this is structured, inspection reports, maintenance notes and engineering documents often hold the context that numbers alone cannot capture. The challenge is bringing that evidence together. Inspection findings may be held separately from operational data, while some of the most useful context remains with the people who know the asset well. A compressor may be operating within its stated limits but behaving differently from previous runs. A slight temperature increase may appear harmless until it is considered alongside recent maintenance or an unusual pressure trend. AI offers a practical way to examine these relationships across much larger volumes of information. By comparing current conditions with previous operating behaviour, it can draw attention to changes that would take far longer to identify manually. That gives engineers more time to decide whether something needs to be investigated. The ability to recognise these signals is becoming more useful as assets remain in service for longer. Equipment condition changes with age and the way a facility operates rarely stays exactly as it was designed.

From signal to decision

Anomaly detection is already one of the most practical applications of AI in industrial operations. A model can learn how a process or piece of equipment normally behaves and flag any deviations before it becomes a problem. However, the engineer still needs to understand what’s changed and why it’s being flagged. The system should help the engineer understand the evidence and decide next actions. A warning or setpoint in isolation doesn’t give the engineer enough to act on by itself. When optimising a process, for example, a recommendation to increase throughput may increase production in the short term, but it may consume more energy or affect equipment condition. Because many of these decisions are also likely to have a direct impact on safety, it’s not enough for the recommendation to sound reasonable; the engineer must also be able to verify it. An operational example from Applied Computing shows how this can work in practice. The company is KBR’s AI technology partner and developed Orbital, the first foundation model built specifically for energy operations, combining physics-grounded intelligence with models across chemical engineering, time-series forecasting and language. On one refinery unit, the amount of energy used for each unit of output had begun to rise without an obvious cause. Orbital compared changes across the unit’s process and utility data and highlighted an instrument reading that had begun to drift. The wider pattern pointed towards a steam trap that was starting to fail, giving engineers a specific area of the plant to investigate. The site’s existing systems and manual review had not identified the connection. A steam trap removes condensate from a steam system while retaining live steam. As it deteriorates, steam may be lost or condensate may build up, affecting energy use and heat transfer without immediately triggering a conventional alarm. In this case, the relationship between the readings

gave engineers an explanation they could check against the expected behaviour of the steam system.

Testing AI answers

Large language models typically generate responses using pattern recognition. They can produce a confident, well-written answer that is completely wrong – what people refer to as hallucination is just prediction of the next word gone wrong. This is where engineers are turning to physics-informed AI. Rather than relying purely on statistical and predictive patterns, these models rely on the real physical and chemical principles that govern the world around us. Here, the physics governing the process, process relationships, and equipment characteristics are built into the model alongside the operating data. Engineers can then compare its output with established simulation models or run the relevant calculations themselves. The result must also make sense against known plant behaviour. For example, Applied Computing’s Orbital AI model was tested using historical and simulated data from Imperial College London’s ABB carbon capture pilot plant.1 The researchscale facility demonstrates post-combustion capture using a monoethanolamine (MEA) solvent. Flue gas passes through an absorber, where lean MEA absorbs the CO2. The resulting rich solvent is preheated and sent to a stripper, where the CO2 is released and the solvent regenerated for reuse. Orbital’s predictions were compared with an established process simulation. It was trained using temperature, pressure, flow and gas composition data recorded under different gas and solvent flow rates. Conditions throughout the loop are closely connected, so a change in temperature or flow in one part can affect capture performance elsewhere. Orbital was benchmarked against published modelling approaches including TimesNet. In the reported results, the root mean square error for its CO2 concentration predictions was 0.057, compared with 0.089 for TimesNet and 0.123 for Imperial’s internal model. As a lower result indicates a closer prediction, this represented a 53.7% reduction in error against the internal model. The model was also used to suggest changes to flow rates and temperatures that could increase capture while reducing energy use. Engineers could test those recommendations through the simulation and check whether they were consistent with the expected thermodynamic behaviour of the solvent loop. However, it’s important to remember that a model developed for one process still has to be qualified for that application. It should be tested using cases where the behaviour and correct response are already understood, including conditions at the edge of its intended operating range. Engineers also need to know when the model should not be used. Poor instrument data can weaken the result. The same applies if the feed composition has changed or the asset enters an operating condition that was absent from the training data. Those limitations should be visible to the person making the decision.

How much should the system do?

Even with more advanced models, human oversight is still essential. AI can highlight patterns and test different scenarios, but it can’t take responsibility for decisions.

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Building around engineering knowledge

Using Orbital on an individual asset requires more than connecting it to plant data. KBR and Applied Computing are doing this through INSITE 3.0, an AI-enabled platform that combines the model with KBR’s engineering knowledge and information from the plant itself. Operating history shows how a unit has been running, but not necessarily whether that performance is healthy. A compressor may have lost efficiency gradually over several years, leaving a pattern that a model could treat as normal. KBR adds the heat and mass balances, performance maps and operating limits that show how the unit was originally designed to work. Historian, laboratory, maintenance and inspection records are then used to reflect how the individual asset behaves today. Engineers can compare that behaviour with the original design and the underlying physics. The engineering checks built into the system can also remain available as experienced people retire or move on.

Figure 1. KBR recently partnered with Applied Computing to develop

the next generation of physics-informed AI platforms for use in oil and gas processes.

It’s possible to look at this in three ways. At the most basic level, AI can be used to monitor conditions and flag anomalies. Next, it can be used in a more advisory role, to suggest actions that engineers can evaluate. Finally, and only in limited cases, AI may be used to optimise specific processes automatically, within tightly defined boundaries. Even then, experienced engineers are still needed to interpret the results, assess the risk and make the final decision.

More time to act

AI will make the greatest practical difference where it helps engineers understand an asset sooner. That could be recognising an equipment issue before it affects production or identifying an opportunity to run a process more efficiently or make better use of an ageing asset. However, unlike the current AI models that we’ve become accustomed to, a new generation of physics-informed models, grounded in reality, will help engineers make more informed choices that they can trust.

Engineers still need to know why

Although AI is changing the way engineers work, they are still ultimately responsible for its outcomes. It’s important that engineers understand what information the model is using and which assumptions sit behind the result. They must also recognise where gaps in the record could affect it. This is particularly important for new engineers entering the industry. Earlier generations often learnt calculations and engineering methods manually before software automated parts of the work. The process gave them a feel for the assumptions behind a result and helped them recognise when an answer looked wrong. AI can conceal more of that working. If the answer appears quickly and is expressed with confidence, there is a risk that it becomes too easy to accept. Engineers need enough grounding in the process to challenge a recommendation and reproduce the reasoning by another route where necessary. As AI adoption grows, their time may shift away from finding and arranging information towards testing what the model suggests, and human judgement will become even more important as automation grows.

Reference

1. https://appliedcomputing.com/more/cs/co2improvement

About the author

Andy Webster, Senior Director Digital & AI, KBR, leads digital strategy across global energy and industrial markets. With operational experience at Shell, Yokogawa and KBC, he has run large-scale digital platforms and asset performance programmes, taking ownership of the P&L outcomes they deliver. He works at the intersection of operations and technology, translating boardroom ambition into results engineers can act on.

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Oilfield Technology - September/October 2026