Oilfield Technology - January/February 2026

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Rotor

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Stator

05 Guest comment Ram Narayanan Sambasivan, Vice President, Sulzer.

06 Operational optimisation under capital discipline

11 The cornerstone of a digital future Gino Hernandez, Head of Global Digital Business for ABB’s Energy Industries division, debates that digital intelligence is the cornerstone of future oilfield operations. 02 Editor’s comment 03 World news

Shola Adekeye and Rolando Gabarron, KBC (A Yokogawa Company) argue that capital-constrained upstream operators are using integrated digital tools to maximise performance and value from existing assets rather than investing in new infrastructure.

The zero-bypass mud lube monitor innovation that’s changing RSS performance. Designed specifically for RSS applications, the patented Stabil Drill Rival RSM Zero-Bypass Mud Lube Motor eliminates motor pressure loss to maximise pad force, improve steering consistency, and simplify system hydraulics. Field proven in over one hundred runs, compatible with all RSS tools, and actively drilling in today’s most demanding well designs.

Stabil Drill is part of the Superior Energy Services family, delivering advanced wellbore technologies and cutting edge innovation.

Discover how Stabil Drill is advancing RSS performance at www.stabildrill.com

14

Using AI to find additional resources in existing oilfields

Josh Dixon, Senior Research Analyst, Upstream, and Kevin Swann, Senior Research Analyst, Upstream, at Wood Mackenzie, argue that AI can help the oil industry unlock up to a trillion barrels from existing fields to meet future demand. 18

The key to the energy sector’s digitalisation ambition

Mark Kelly, head of digital and innovation at Bilfinger, UK, discusses how infrastructure is the key to the energy sector’s digitisation ambitions. 22

The unseen risks of AI

Graham Faiz, Head of Digital Energy at DNV, explores the risks that exist in offshore safety mechanisms and proposes a template for systemic AI safety. 25

External pipe corrosion protection on FPSOs

Hani Almufti, Cogbill Construction, discusses corrosion under pipe supports (CUPS) on FPSOs, focusing on the challenges, mechanisms, and a novel mitigation solution.

31 Smarter water treatment

Dave Sheldrake, Veolia – Water Tech, addresses securing offshore resilience with smarter water treatment.

35 Securing Europe’s energy transition

Kleopatra Kyrimi, Sarens Group Marketing & Communications Manager, Sarens, Spain, discusses how Europe is responding to geopolitical disruptions in gas supply by accelerating the energy transition, investing in domestic gas production and cleaner alternatives, and relying on logistics and heavy-lifting operations to ensure energy security and infrastructure development.

38

Rod lift optimisation in the horizontal well era

Peter Westerkamp, Vice President of Automation – Global Sales, LUFKIN Industries, highlights why the industry must adopt new, physics-based algorithms designed specifically for modern well trajectories.

41 Standout solutions

Michael Coburn, Director of Engineering and Project Management, Blackmer (PSG Grand Rapids), USA, analyses the challenges of pumping liquids in the oil and gas industry, and explains why magnetically driven sliding vane pumps are emerging as a superior solution.

January/February 2026

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Comment

Emilie Grant, Assistant Editor emilie.grant@oilfieldtechnology.com

Venezuela: a country on the northern coast of South America, known for its diverse geography and many of its natural attractions including Angel Falls, the Andes, and – most poignantly in 2026 – oil.

It is undeniable that there is a degree of uncertainty facing the upstream oil and gas industry. Wood Mackenzie states ‘US tight oil output will decline by 200 000 bpd in 2026 – the first contraction without a market crash.’1 The heavy reliance that the world has on US oil and gas supply and upstream investment means that the shift is not insignificant for global markets.

With this being said, it is no surprise the jeopardy that the US attack on Venezuela and the demand to acquire Greenland has had on geopolitical tensions, as well as the global oil market. Ramnivas Mundada, Director of Economic Research and Companies at GlobalData, noted that “Venezuela is still highly dependent on hydrocarbon export receipts for foreign exchange and fiscal capacity. Even without major physical damage to fields or terminals, oil flows can be disrupted by softer but powerful mechanisms”. Taking this into considerations, there is no doubt in people’s minds that this was strategic to secure greater oil output.2

Further to this, there has been an increased interest in Greenland in recent years, that came to a fever-pitch in January 2026. This is attributed to its abundance of natural resources, including rare earth minerals, uranium, and iron – all of which are becoming more easily accessible due to the rise in the earth temperature and the melting of the ice sheet that covers the country.3 Despite President Tump stating that this acquisition is in the interest of ‘national security’, it is undeniable that this may not have been the sole motivation. Initially, the threat of new tariffs being imposed (10% from 1 February on goods from Denmark, Finland, France, Germany, the Netherlands, Norway, Sweden and the UK; increasing to 25% if no agreement was met by 1 June),4 it felt like we were back where we started, where tariff threats were used as bargaining chips. Following a discussion with NATO Secretary General Mark Rutte at the World Economic Forum, President Trump rounded back on the tariffs.5 However, it is precisely this political uncertainty that is further leading to market volatility, and the likelihood of more radical fluctuations in oil prices this coming year.

Energy security is going to be a key trend of 2026, often due to political and economic tensions. As of Monday, 19 January, we have already seen oil prices trading lower as a result of the uncertainty between the transatlantic relations. Norway’s Equinor was among the energy stocks leading the sector’s losses, down approximately 3.4%. France’s TotalEnergies, Britain’s Shell, and BP fell between 1% and 1.5%, respectively.6 Energy security volatility is certainly at the forefront of people’s minds as a result. But what will happen in the long run? Only time will tell.

1. https://www.oilfieldtechnology.com/offshore-and-subsea/09012026/wood-mackenzie-global-upstream-fivethings-to-look-for-in-2026/

2. https://www.globaldata.com/media/business-fundamentals/us-attack-on-venezuela-oil-metals-fx-and-equitymarkets-brace-for-volatility-says-globaldata/

3. https://www.bbc.co.uk/news/articles/c74x4m71pmjo

4. https://edition.cnn.com/2026/01/18/business/europe-greenland-trump-tariffs-trade

5. https://commonslibrary.parliament.uk/research-briefings/cbp-10472/

6. https://www.cnbc.com/2026/01/19/trump-greenland-tariffs-exposed-exporters-europe.html

World news

Equinor awarded 35 new production licenses on the Norwegian continental shelf

Equinor has been awarded 35 new production licenses by the Norwegian Ministry of Energy in this year’s APA, Awards in Predefined Areas.

Equinor will gain access to attractive acreage in the North Sea, the Norwegian Sea and the Barents Sea, strengthening the foundation for the company’s exploration activity, production and long-term value creation on the Norwegian continental shelf (NCS).

Twenty-one of the awards are located in the North Sea, 10 in the Norwegian Sea, and four in the Barents Sea, 17 of the licences with Equinor as an operator.

“We are very pleased with the APA round, which facilitates our plans for a continued high level of activity within exploration. A strong year has been completed with 14 discoveries in 2025, seven of them Equinor operated. This amounts to approximately 125 million boe of new recoverable oil, with a potential for even more,” says Jez Averty, Equinor’s senior vice president for subsurface, the Norwegian continental shelf.

The licenses are awarded within areas with existing infrastructure and new areas.

“Our geological knowledge is high, and we are constantly learning more through further exploration. Awards in lesser-known areas, such as we have received in the northeastern part of the North Sea and in the southwestern Møre Basin, provide new and exciting opportunities,” says Averty.

Equinor plans to drill 20 - 30 exploration wells annually. 80% of the exploration will be near existing infrastructure, while 20% will explore new concepts and lesser-known areas.

Discovery and maturation of new resources are necessary for Equinor to develop six to eight new subsea developments each year until 2035. This is a significant increase from the current level.

As Europe’s largest energy provider, Equinor plays a key role in European energy security and energy transition.

“Access to new acreage is crucial for our ambition to maintain a high level of production and predictable energy deliveries to Europe from the NCS towards 2035. There is still a lot of energy left on the NCS, but we need new discoveries to curb the expected production decline. Phasing in oil and gas from new discoveries to existing infrastructure is a core task going forward,” Averty concludes.

EnerMech awarded Saipem contract for Whiptail subsea pre-commissioning project offshore Guyana

EnerMech has been awarded a subsea pre-commissioning services contract by Saipem for the Whiptail Development, located approximately 200 miles offshore Guyana in the Stabroek Block operated by ExxonMobil Guyana.

This award marks EnerMech’s first project on the Whiptail field and builds on its proven track record supporting subsea pre-commissioning campaigns offshore Guyana, including Liza Phase 2, Payara, Yellowtail, and Uaru fields. Under the new contract, the integrated technical solutions specialist will deliver a full suite of activities, including:

Ì Flooding, cleaning and hydrotesting of subsea risers and flowlines.

Ì Umbilical post-load out, transit and lay monitoring from the offshore construction vessel.

Ì Dynamic umbilical lay monitoring and post-installation testing from the FPSO unit.

EnerMech CEO Charles Davison, Jr. said: “This latest award for our Energy Solutions team is another important milestone in our Guyana growth story. It underscores the trust that leading offshore contractors like Saipem continue to place in our people, technology and track record.”

To meet the growing demand for offshore energy services in the region, EnerMech is establishing a new facility in Georgetown and executing a phased equipment acquisition strategy, including the addition of remote flooding units (RFUs) and subsea test pumps (STPs). These investments will support future projects and enable faster, more efficient mobilisation of equipment locally.

Malta

Viridien has signed an agreement with the Government of Malta to invest in an integrated multi-client dataset for the country’s offshore area. By revitalising existing seismic and well data, this project will advance the understanding and promotion of Malta’s offshore petroleum potential in the Central Mediterranean.

Lebanon

TotalEnergies and its partners Eni and QatarEnergy have signed an agreement with the Lebanese government to enter Block 8 exploration permit offshore Lebanon. The consortium’s initial work programme on Block 8 consists of the acquisition of a 1200 km2 3D seismic survey, in order to further assess the area’s exploration potential.

Venezuela

Venezuela produced 820 000 bpd in November 2025, but output is expected to decline following the US naval blockade imposed on 17 December. Wood Mackenzie anticipated production could fall by 200 000 - 300 000 bpd in early 2026 as market participants withdraw and high inventories force curtailment.

Africa

Recent months have witnessed a surge in seismic data deals and renewed exploration activity across Africa. The combination of new 3D data acquisition, reprocessing of legacy surveys and faster permitting is offering clearer geological insight and reducing risk – giving governments and investors renewed confidence in frontier exploration.

Indonesia

Eni announces a significant gas discovery in the Konta-1 exploration well, drilled in the Muara Bakau PSC, in the Kutei Basin, about 50 km off the coast of East Kalimantan in Indonesia. Estimates indicate 600 billion ft3 of gas initially in place (GIIP) with a potential upside beyond 1 trillion ft3

World news

Diary dates

10 - 11 March 2026

StocExpo 2026

Rotterdam, Netherlands

https://www.stocexpo.com/en/

18 March 2026

World Pipelines CCS Forum - London 2026

London, England

https://www.worldpipelines.com/ ccsforum2026

04 - 06 May 2026

Offshore Technology Conference (OTC) 2026

Houston, Texas, USA https://2026.otcnet.org

14 - 17 September 2026

Gastech 2026

Bangkok, Thailand

https://www.gastechevent.com/

Web news highlights

Ì PXGEO boosts leadership team with two key appointments.

Ì The real problem in oil and gas procurement: measuring what doesn’t matter

Ì Wood Mackenzie global upstream: five things to look for in 2026

Ì Sentinel welcomes Willem Boon Von Ochssee as Non-Executive Director

Ì INEOS Energy announces new Norphlet oil discovery in the Gulf of Mexico

Ì Subsea7 awarded contract offshore US

Ì Mozambique LNG announces the full restart of all its activities onshore and offshore in Mozambique

To read more about these stories and for more event listings go to: www.oilfieldtechnology.com

Wood Mackenzie: five subsurface themes shaping upstream exploration and development in 2026

Global upstream exploration spending is expected to dip below the US$20 billion annual average of the last five years as low oil prices pressure the sector, according to Wood Mackenzie. Appetites for strategic growth remain strong, but companies are focusing on selective high-impact drilling rather than broad-based spending.

Major oil companies are pursuing giant field redevelopment partnerships with national oil companies to secure discovered resources without exploration risk. The exploration landscape is shifting from traditional licensing rounds toward governmentto-government deals and direct negotiation. Ocean Bottom Node seismic technology and artificial intelligence are compressing decision timelines from months to weeks. Next-generation geothermal technologies face a defining year as flagship projects must demonstrate commercial scalability.

“The upstream sector is recalibrating its approach to resource capture in 2026,” said Andrew Latham, Senior Vice President, Energy Research at Wood Mackenzie. “Exploration spending remains disciplined, but the industry is pursuing multiple pathways to growth – from play-opening wildcats in the Atlantic margin to unlocking billions of barrels from producing fields through IOC-NOC partnerships.”

“Technology is accelerating both discovery and development of conventional hydrocarbons,” Latham said. “The question is whether next-generation geothermal can prove it belongs in the same commercial league and meet 24/7 baseload power demand.”

Wood Mackenzie identifies five key subsurface themes for 2026: high-impact exploration focused on play-opening prospects despite spending pressures; strategic acreage access replaces competitive bidding; major oil companies target NOC partnerships to redevelop giant fields; Ocean Bottom Node seismic and AI workflows compress exploration decision cycles; and next-generation geothermal faces commercialisation test.

Baker Hughes launches autonomous well construction solution at Annual Meeting in Florence

Baker Hughes announced the launch of the Kantori™ autonomous well construction solution, a new unified digital service that provides intelligent operations and streamlined workflows across every stage of the well construction process ,at the company’s 26th Annual Meeting in Florence, Italy.

Kantori combines artificial intelligence and physics-based models with real-time data analytics to continually optimise performance and enable automation across planning, execution and monitoring activities. This approach supports rapid decision making with limited human intervention, reducing nonproductive time and variability during well construction operations.

“Autonomous drilling has opened new frontiers for our industry, replacing reactive operations with intelligent systems that can learn, adapt and optimise performance in real time,” said Amerino Gatti, Executive Vice President, Oilfield Services & Equipment at Baker Hughes. “This digitally driven approach, built on decades of drilling expertise and intelligent engineering, is making well construction smarter, safer and more predictable. Baker Hughes has set the standard in this field, and Kantori marks the next chapter of digital innovation in well construction.”

Kantori supports the entire well construction life cycle, from connectivity and data integration to well planning and performance optimisation. The solution is scalable by design and adapts to customer needs, whether for a single well or across an entire field. Corva, which provides real-time analytics and predictive intelligence, is seamlessly integrated with Kantori for enhanced flexibility and control.

Kantori is part of Baker Hughes’ end-to-end portfolio of digital solutions, joining LeucipaTM automated field production solution and CordantTM Asset Performance Management software.

Guest comment

Ram Narayanan Sambasivan, Vice President, Sulzer

There are significant pressures on the oil and gas industry to improve efficiency in the face of geo-economic disruptions and persistent inflation, and offshore platforms offer an under addressed opportunity to optimise energy use in response.

One promising solution to do this lies in Hydraulic Power Recovery Turbines (HPRTs) – a technology already proven downstream, now offering untapped potential for upstream operations to reduce energy costs without increasing carbon emissions.

Offshore operations rely heavily on fuel to power gas turbines or diesel generators – major cost drivers. Floating Production Storage and Offloading (FPSO) installations require a reliable source of energy to ensure continuous operation. Traditionally, crude oil is extracted from the seabed, the produced water is separated and treated, with a portion consumed while the excess water is returned to the sea or, in technical terms, ‘overboarded’. Instead, by passing the overboarded water through a vertical HPRT – requiring no more space than the existing overboard pipe – a mid-to-large capacity FPSO could recover approximately 5% of its 20 - 25 MW power consumption. As a result, fewer gas and diesel deliveries are needed for power generation, which translates into lower energy costs and reduced operational risk.

In extreme offshore conditions, energy recovery can be more than a cost-saving measure – it can be a lifeline. For example, during India’s monsoon season from June to September, certain regions receive as much as 90% of their total annual rainfall.1 That prolonged cloud cover shuts off the potential for power from solar panels on unmanned oil platforms in the region. Those heavy rains are often combined with high winds, causing choppy seas and making it difficult to deliver the diesel needed to power the generators relied on by platforms. These adverse weather conditions can combine to leave the unmanned oil platforms at risk of unreliable energy sources over a prolonged period.

By channelling a small portion of water used for injection in a closed loop through an HPRT, operators will be able to power up the electricity needed for their equipment in unmanned platforms. This innovative application opens possibilities for more reliable operations in some of the most extreme conditions, such as the monsoon season in India. Even where offshore platforms operate in less challenging conditions, an HPRT can provide a layer of security when choppy seas and overcast weather combine to frustrate the ability to generate power from other sources.

In a challenging economic environment, upstream operators must explore energy recovery solutions. HPRTs enable companies to maintain production levels while reducing energy costs. The combined result is a stronger bottom line – a diamond in the deep for oil companies.

1. https://www.cpc.ncep.noaa.gov/products/assessments/assess_96/india.html

Shola Adekeye and Rolando Gabarron, KBC (A Yokogawa Company) argue that capitalconstrained upstream operators are using integrated digital tools to maximise performance and value from existing assets rather than investing in new infrastructure.

n upstream oil and gas, capital discipline increasingly prioritises optimising existing assets rather than adding new physical infrastructure. Capital discipline favours smaller, phased investments, fewer new projects, and deeper scrutiny of capital efficiency, reliability, and performance of existing assets using cloud-enabled tools.

At the same time, the International Energy Agency (IEA) has acknowledged that investment in oil and gas has fallen sharply, reporting that upstream capital spending declined by approximately 35% between 2015 and 2025. The IEA cautions that sustaining current production levels will require hundreds of billions of dollars in annual investment, especially as decline rates of hydrocarbon reservoirs accelerate.

In parallel, analysts now project further capital tightening. Outlooks referenced by Wood Mackenzie indicate upstream spending cuts in 2026. These projections reflect how operators must balance capital spending, commodity price risk, and portfolio diversification priorities. Together, these dynamics place renewed emphasis on capital efficiency and asset performance.

In this environment, upstream operators’ early design and operating assumptions lock in cost, risk, and emissions performance. Several factors drive this renewed focus on capital efficiency:

Ì Energy security has returned as a strategic priority following recent geopolitical and global supply chain disruptions. Governments and operators alike are reassessing upstream resilience to ensure reliable and secure energy supplies amid heightened market volatility.

Ì More Artificial Intelligence (AI), Machine Learning (ML), automation and advanced production enhancement technology are increasingly being applied across Exploration and Production (E&P) operations. These tools are intended to help improve production, reduce operating costs, and manage growing asset complexity. Digital optimisation can lift production by several percentage points, directly lowering lifting costs and improving margins under capital constraints.

Ì Global demand for natural gas continues to rise, both as a transition fuel supporting lowercarbon energy systems and as a reliable power source for energy-intensive infrastructure such as data centres. Natural gas demand is expected to remain resilient over the medium term. This trend reinforces the importance of efficient, well-managed upstream gas assets.

Against this backdrop, upstream operators face increasing pressure to extract greater value from assets, especially in remote environments. They must do so while maintaining safety. These challenges shift operators toward tightly integrated operating models spanning production optimisation, asset management, and facilities design.

Operational digitalisation under capital discipline

While capital discipline has become the dominant constraint shaping upstream investment decisions, it has also accelerated a shift in how operators extract value from existing assets. Rather than replace infrastructure, effective responses to capital tightening increasingly focus on integrating data, physics-based models, and operational workflows into cohesive decision systems.

Traditional approaches often treat production surveillance, allocation, asset management, and optimisation as disconnected functions. Under capital constraints, this fragmentation becomes a liability. Operators increasingly require continuous visualisation into well and network

performance without new field hardware or frequent manual intervention.

Cloud-based virtual flow metering, integrated asset models, and near-real-time operational analytics have emerged as practical enablers of this shift. When embedded within daily workflows, these capabilities move teams from periodic insight to continuous decision support. This transition improves production confidence, accelerates response times, and reduces the economic impact of uncertainty, particularly in mature or remote assets with high intervention costs.

From an operational standpoint, capital discipline has therefore reframed digitalisation from a technology initiative into a core production strategy. The value lies not in any single model or dashboard, but in how measurement, optimisation, and execution are connected across the asset lifecycle.

Lifting cost reduction and asset performance

Upstream operators focus on lowering lifting costs by approximately 5 - 10%. These gains are typically achieved through improved production surveillance, asset optimisation, and digital workflows. These approaches are applied across the production system rather than any single segment of the production workflow. Together, these three areas form the primary levers operators use to improve efficiency, manage asset complexity, and strengthen field economics under capital constraints.

Operational levers for upstream performance

Production optimisation

Where can operators unlock production gains without adding capital or hardware? Production optimisation remains a central focus for upstream operators seeking to maximise throughput, stabilise operations, and reduce unplanned deferment. These objectives combine domain expertise with first-principle, physics-based simulation and near-real-time operational data. Across a range of

upstream applications, operators applying these approaches have achieved production efficiency improvements of approximately 2.5 - 10%. Figure 1 shows an integrated operational dashboard that supports production surveillance and optimisation across wells.

Rather than serving as a static reporting view, this type of dashboard supports continuous production optimisation by highlighting deviations, ranking wells by opportunity, and enabling faster operational response.

Improving production visualisation without adding hardware has become a critical optimisation lever. For example, cloud-based virtual flow metering (VFM) applies physics-based multiphase modelling and near-real-time analytics to estimate oil, gas, and water rates for back-allocation and daily production accounting. By augmenting periodic well tests and existing instrumentation, these techniques improve allocation accuracy, accelerate anomaly detection, and enable faster operational responses across brownfield and unconventional assets. When integrated into production surveillance dashboards, VFM helps close gaps between tests, supporting more informed day-to-day optimisation rather than waiting for the next well test cycle. These systems can operate alongside multiphase flow meters (MPFM), test separators, and welltesting units without additional instrumentation.

Beyond rate estimation, physics-based simulation tools support a wide range of upstream optimisation and flow assurance challenges, including:

Ì Hydrate formation risk.

Ì Wax deposition prediction and mitigation.

Ì Mercury partitioning.

Ì Life-of-field simulation.

Ì Gas lift optimisation.

Ì Facility debottlenecking.

These first-principle, physics-based simulations provide operators with a detailed understanding of thermodynamic and flow behaviour under real operating conditions. This insight detects risks earlier and improves confidence in decision making.

For example, these simulation insights combined with ML can detect hydrate formation risk in pipelines. Advanced analytics can then evaluate mitigation options, such as adjusting the chemical injection rates or operating parameters. These insights support earlier anomaly detection and more proactive operational response. Beyond incremental uplift, these approaches help operators build confidence under changing conditions.

Asset management

As upstream facilities age, maintenance costs rise and equipment reliability becomes increasingly critical to production efficiency and profitability. In offshore and remote environments particularly, even small production losses can have disproportionate economic impact. In the authors’ experience, a 1% loss in production can exceed the annual maintenance budget of a single offshore asset.

Operators are shifting toward data-driven asset management strategies to improve reliability, predictive insight, and risk reduction. Key elements include:

Ì Uptime improvements of approximately 1 - 5%.

Ì Smart asset management where technologyaugmented critical equipment reduces dependence on large onsite maintenance workforces and enables data-driven decision making.

Figure 1. Operational dashboard showing surveillance and performance monitoring across multiple wells and assets.

Ì Enterprise asset management systems supported by subject matter expertise.

Ì Time-at-risk reductions of up to 30% via digitalisation and remote monitoring; task optimisation and planning, automation and robotics.

Ì A shift from reactive and preventive maintenance to predictive and proactive strategies.

By improving visibility into equipment health and maintenance schedules, operators can better align maintenance with production objectives while reducing operational risk.

Facilities of the future

Most upstream assets are designed for peak production. As fields mature and production declines, operational complexities increase. These include increased water cut, changing flow regimes, and greater variability in operating conditions. Together, these factors raise the per barrel cost of sustaining production.

Facilities of the Future (FotF) concepts address this challenge via Normally Unattended Facilities (NUF) operated from a centralised Integrated Operating Centre (IOC).

The goal of the FotF is integrated optimisation across production, maintenance, and operations via:

Ì Reduced time-at-risk for employees.

Ì Reduced unplanned deferment through predictive capabilities and faster response time to operational upsets.

Ì Optimised production across multiple assets to maximise revenue or lower lifting costs.

While FotF programmes typically require targeted capital investment, these investments can be offset by sustained operating cost reductions. Integrated operational and digital strategies have delivered lifting-cost improvements of approximately 10%/bbl. In oil-price scenarios near US$50/bbl, upstream project models often target internal rates of return above 20% over a 10 year horizon, making sustained lifting-cost reductions strategically critical.

These integrated capabilities reflect the operating direction enabled by modern cloud-based production monitoring and digital flowmeter platforms.

Case study: real-time production monitoring and gas-lift optimisation

A large upstream operator was managing a gas-lifted production system. The operator needed to better understand how gas-lift allocation interacted across the asset. Conventional surveillance methods relied on periodic well tests and multiphase flow meters. To address these limitations, the operator implemented a solution built around an Integrated Asset Model (IAM) and VFM.

The primary objective was to develop a VFM model capable of accurately estimating the flow rate for the chosen wells and demonstrating gas-lift optimisation for the client’s wells. Success was

measured by flow-rate accuracy and the effectiveness of optimisation strategies on well performance.

A comprehensive characterisation of reservoir fluids was conducted using available pressure-volume-temperature (PVT) data. The integrated model was tuned to provide accurate measurements of the flow rates and operating conditions within the wells. A Gas Lift Optimisation (GLO) module was implemented to enhance the efficiency of the gas-lift operation. VFM delivered continuous well-level flow estimates to enhance the client’s existing allocation methodology, well ranking, and well test scheduling. Figure 2 illustrates the alerts used to prioritise operational response across the gas-lifted wells. By replacing frequent physical well tests with high-accuracy virtual metering, the operator achieved:

Ì Approximately 2% production enhancement through gas-lift.

Ì US$6 million/y in incremental value.

Ì ≥95% accuracy in well-level flow-rate estimates using VFM.

Ì A 40 - 60% reduction in engineering and surveillance man-hours through automation, KPI-driven workflows, and centralised monitoring.

Integrated capabilities for upstream decisionmaking

When capital is constrained and operational assumptions carry greater financial consequences, upstream decision-making depends less on individual tools and more on how capabilities are integrated across the asset lifecycle.

What distinguishes upstream organisations that consistently make sound decisions under uncertainty? It is not any single model, dashboard, or workflow. It is the ability to integrate how production is measured, how assets are managed, and how decisions are executed across various fields and/or asset portfolios.

Evaluation of upstream developments highlights several characteristics that consistently support effective decision-making and value realisation:

Ì Production optimisation begins with visibility. Near-real-time VFM provides continuous, physics-based estimates of well and network performance. This allows operators to detect losses earlier, optimise gas-lift allocation faster, and act before deferment occurs, even when instrumentation is limited. These cloud-based digital twins provide continuous monitoring across production and processing systems to support forecasting, diagnostics, and optimisation.

Ì Asset management builds on that same visibility. When wells, flowlines, and facilities are monitored through a shared production model, reliability issues, flow-assurance risks, and equipment degradation can be identified earlier and addressed proactively. Modern VFM platforms integrate with sensors, historians, and SCADA systems to unify operational context across teams. This improves uptime, reduces unnecessary interventions, and lowers operating risk as assets mature.

Ì FotF extend these capabilities through enterprise-wide production data visibility and integrated operating workflows. By connecting production data, models, and workflows across disciplines, operators can reduce on-site exposure and streamline decision cycles across complex asset portfolios.

Together, these integrated capabilities transform how upstream assets are run. Continuous, softwarebased flow visibility improves decision quality and reinforces operational confidence. In capital-constrained environments, this integration is what allows operators to extract more value from existing assets while maintaining safety, reliability, and disciplined capital deployment.

Figure 2. Automated alerts flag deviations from expected performance.

Gino Hernandez, Head of Global Digital Business for ABB’s Energy Industries division, debates that digital intelligence is the cornerstone of future oilfield operations.

he oil and gas sector has always been defined by its ability to adapt. Every major technological shift, from the introduction of automation platforms to emergency shutdown systems, has grown out of a practical need to operate safely, efficiently and reliably.

We have now entered the next phase of the sector’s evolution – the digital oilfield. In this environment, data, connectivity and intelligence are becoming just as critical to operations as instrumentation and engineering design. Across the projects that ABB has collaborated on globally, we see operators moving beyond a mindset where digital technologies are viewed as enhancements but recognised as operational necessities.

This shift comes at a time of competing pressures to do more with less. Many fields are operating with legacy infrastructure, yet there is an expectation to increase production while simultaneously reducing operational emissions. Every decision now must balance performance, cost and increased sustainability.

Digital solutions, whether asset performance management, process optimisation or AI-assisted

decision support, are proving to be the force multipliers that help operators meet these demands with greater precision and confidence.

It is important that we do not view the value of digitalisation being the collection of data, as its reach extends far beyond. The true potential lies in the ability to turn that data and the insights gained from it into meaningful action. Many offshore and onshore assets generate decades of process data, yet historically only a fraction has influenced real-time operational decision-making.

Today, advanced analytics can extract meaningful insight from these large, diverse data sets, bridging operational,

electrical and mechanical information. This contextual intelligence is an important step change for operators. It enables teams to run assets predictively rather than reactively, determining how to respond to failures before they even happen.

Strengthening fundamentals through connected insight

As digital capabilities mature, many of the most successful operators begin by strengthening the fundamentals. This means establishing reliable data flows from sensors and control systems, integrating information across disciplines and ensuring teams operate from a unified source of truth. Once that visibility is in place, performance improvements follow.

Applying predictive analytics to rotating equipment, valves or heat exchangers illustrates this clearly as it allows teams to address degradation before it escalates into unplanned downtime. In facilities where this shift has taken hold, maintenance routines are becoming more targeted and less intrusive, while overall asset availability continues to rise.

The impact is evident in projects such as Ormen Lange offshore gas field in Norway, where ABB has delivered cloudbased monitoring, predictive asset management and advanced condition monitoring. Through remote operations and predictive workflows, the field has consistently delivered more than 99% uptime and reduced on-site presence, enhancing safety and lowering operational cost.

Similarly, in Australia’s Barossa field, condition monitoring has been deployed across more than 1000 assets. The goal is to help teams detect deviations early, refine operational sequences and support commissioning of one of the industry’s most advanced gas FPSOs. These examples demonstrate how digital layers strengthen physical infrastructure, extend asset life and reduce operational exposure.

Optimising the energy ecosystem

As the energy landscape becomes more complex, there is growing recognition that optimising an oilfield today means optimising the entire energy ecosystem around it. Gas compression, power generation, water treatment, flare control and renewable integration are no longer isolated components, and each influences the others in subtle but significant ways. Modern digital platforms now allow operators to co-ordinate them more dynamically than was previously possible.

By analysing energy flows in real time, identifying inefficiencies and adjusting setpoints dynamically, operators can reduce unnecessary variability and improve the stability of core processes. We have seen this approach deliver substantial value across the energy sector, from improved steam management in refinery utilities to more consistent performance in facilities operating with variable feedstocks or ambient conditions.

An example is found in Thailand, where the ABB AbilityTM OPTIMAX® for Steam and Power solution was deployed at a combined heat and power system. The plant improved efficiency and achieved a 50% reduction in steam-pressure variability through the deployment of advanced process control and energy optimisation. The result was greater production stability, lower fuel use and reduced operating cost.

Digitalisation is also proving essential at large-scale renewable-integrated sites. The Al Dhafra solar project in Abu

Figure 1. In control rooms, digital technology is not viewed as an enhancement but an operational necessity.

Figure 2. Creating a digital oilfield does not require wholesale replacement of what already exists. Many systems benefit from adding modular digital layers and integration of data from previously siloed systems.

Figure 3. Optimising an oilfield means optimising the entire ecosystem, allowing operators to dynamically coordinate different elements.

Dhabi, which is the world’s largest single-site PV plant, uses ABB’s real-time monitoring and analytics solutions to detect deviations early and maintain output consistency across millions of solar panels. These capabilities are increasingly relevant as operators globally seek to integrate traditional power systems with low-carbon technologies.

Remote operations providing strategic advantage

Remote operations is another area where the digital oilfield is demonstrating its value. What may have begun primarily as a means to enhance the safety of offshore personnel operating in remote and hazardous environments, has evolved into a powerful operating model in its own right. Modern control and monitoring technologies now enable teams to support multiple facilities from a central location, improving responsiveness while maintaining high reliability.

We have seen this across numerous assets where remote capabilities have been fully deployed, resulting in reduced on-site interventions and faster issue resolution. Those that have used these solutions have also seen cost efficiencies and the ability to attract new talent – often deterred by remote work – has become less challenging.

The deployment of remote operations is clearly illustrated in our work on the Aasta Hansteen field. Through virtual start-up simulations, operators reduced more than 1000 manual interventions to just 20 structured steps. This approach saved 2700 engineering hours and brought first gas online 40 days ahead of schedule. It highlights the broader shift towards model-based operational readiness and remote decision-making.

Digital transformation does not require a wholesale replacement of existing infrastructure. In many cases, the most effective strategy is to build on what is already in place connecting legacy equipment, adding modular digital layers and integrating data from systems that previously operated in isolation. This staged approach acknowledges the reality of brownfield sites while creating a scalable foundation for future enhancements.

AI and the path towards autonomous operations

As digital maturity grows, operators are beginning to move from connected insight towards augmented and semiautonomous operations. Autonomous and semi-autonomous operations are not about removing human expertise – it is the opposite. They take care of day-to-day activities so that humans can lend their insights and expertise into solving technical challenges and higher volume tasks.

Before a system can safely operate with minimal intervention, it must be able to interpret its environment, understand the constraints that govern safe performance and apply control actions consistently. Digital twins, enhanced sensing, robust data architectures and embedded AI make this possible. They allow us to simulate scenarios, verify control logic and build confidence in how the system behaves long before it goes live.

As these technologies mature, we are seeing a gradual shift toward operations where routine adjustments are handled automatically, while specialists step in only when conditions fall outside expected parameters.

AI is playing a central role in the journey towards autonomous. AI models are forecasting behaviours, identifying inefficiencies and recommending optimal control actions built on years of historical data that were previously too complex to interpret manually.

In future, operator-assist tools will become even more immersive, helping teams detect anomalies earlier, simulate outcomes and understand root causes with greater clarity. We see autonomy growing not from removing human judgement, but from enabling teams to apply it where it adds the most value. The shift does not remove human oversight: we believe that it elevates it and makes it even more critical.

The next chapter of the digital oilfield

The digital oilfield is not a single technology or a dramatic overnight transition. It is a continuous progression that builds on decades of automation expertise while opening the door to more predictive, efficient and resilient ways of working. The operators making the greatest progress are those approaching digitalisation as an engineering discipline whereby solutions strengthen instrumentation, unify systems, embed cyber security and build trust in the data that underpins every operational decision.

With these foundations in place, the path to semiautonomous operations becomes clear. Routine optimisation can be automated. Anomalies can be detected earlier. Multidisciplinary teams can collaborate seamlessly across sites and geographies. The result is an operating model far better suited to the scale, complexity and sustainability expectations of the modern energy landscape.

For those responsible for running oilfields, this evolution is about preparing for a future in which secure, intelligent and increasingly autonomous operations will be essential. With well-grounded digitalisation, the oil and gas sector is positioned to operate more safely, efficiently and sustainably in the years ahead.

Figure 4. As digital maturity grows, more operations will become semi or even fully autonomous, enabling safer and more efficient operations.

Josh Dixon, Senior Research Analyst, Upstream, and Kevin Swann, Senior Research Analyst, Upstream, at Wood Mackenzie, argue that AI can help the oil industry unlock up to a trillion barrels from existing fields to meet future demand.

he global oil industry faces a 300 billion bbl supply shortfall by 2050. With oil demand now expected to peak in 2032 rather than 2030, artificial intelligence (AI) emerges as a critical tool for unlocking resources hidden within existing fields. Wood Mackenzie’s subsurface experts explore how AI can identify opportunities to meet this challenge through optimising existing fields and high-grading exploration.

Why do we need to unlock new supply?

Oil demand peak has shifted from 2030 to 2032, demonstrating the energy transition’s slower pace than anticipated. Wood Mackenzie’s latest ‘Energy Transition Outlook’ report shows oil consumption remaining above 100 million bpd through 2050. This resilient demand will intensify pressure on the upstream industry to deliver new supply whilst maintaining capital discipline.

Production from assets already onstream or justified for development will decline under current investment plans from just over 100 million bpd today to 50 million bpd by 2050. Cumulatively, this trajectory creates an almost 300 billion bbl shortfall between supply and demand. New discoveries, whilst valuable for displacing higher-cost barrels, fall far short of addressing supply requirements.

The industry’s vast inventory of almost 2 trillion bbls of discovered but undeveloped greenfield resources offers limited relief. Barely 10% prove commercially viable at current investment hurdles. Traditional exploration will play its part but cannot bridge a gap of this scale. Even Guyana, the 21st century’s biggest new play with 15 billion bbls of oil, barely makes a dent.

What can AI bring to the table?

This supply challenge demands innovative solutions beyond conventional exploration. AI-powered tools become essential for identifying advantaged resources – those that are low cost, low carbon, reliable and fast to market. By identifying where operators can extract significantly more oil from producing reservoirs, AI offers a practical solution to the supply challenge.

Companies across the industry deploy AI-powered techniques, revolutionising everything from seismic processing to drilling optimisation. Wood Mackenzie’s AI-powered analogues feature can identify which fields lag global recovery factor trends and explore why they fall short.

This enables geologists and engineers to reduce uncertainty and explore performance upside.

Field analogue analysis has long suffered from user bias and fragmented datasets. Analysts would manually filter through expansive but incomplete data, delivering results that lacked context, ranking, and objectivity. This approach often missed critical relationships between assets and provided only obvious results from adjacent fields already familiar to users.

Wood Mackenzie’s Analogues feature places AI in the driver’s seat. The system currently analyses over 35 000 global conventional oil and gas fields using comprehensive subsurface and commercial datasets, updated weekly. Rather than relying on prescriptive data filtering, the AI-powered workflow considers all field subsurface and commercial attributes. This approach provides holistic assessment of field similarities and uncovers previously overlooked relationships between assets.

The Analogues feature identifies each field’s closest matches by assessing rock properties, fluid characteristics and commercial factors. The system eliminates human bias inherent in traditional filtering approaches which find only exact matches to prescriptive search criteria. The top 50 analogues are presented to users for further investigation depending on technical questions.

Wood Mackenzie’s initial analysis reveals that optimised recovery from existing fields could yield up to an additional 1 trillion bbls of oil. By identifying global analogues of existing fields and exploring recovery factors these fields deliver, this analysis shows significant reserves upside remains. The industry’s current plans will recover 29% of oil in place from major fields (those with 50 million bbls or more of in-place reserves and resources), 15% of which has already been produced.

Benchmarking against betterperforming global analogues suggests an additional 6 - 12% recovery could be delivered if each field achieved best-inclass recovery rates of their analogue peer group. This upside is already being delivered today from analogous fields using existing technologies and development practices. It requires no unproven or undeveloped technologies or techniques.

Whilst 12% improvement may appear modest, this scenario would translate to approximately 1 trillion additional bbls. This almost doubles remaining recovery potential from existing assets.

Challenges remain

Analogous fields show recovery upside is technically achievable, but other considerations cast doubt on whether this additional production will be delivered in all locations. Conditions that enable success in some fields may not apply in other countries and regions. Factors such as strict emissions regulations and unfavourable fiscal regimes mean this recovery upside may not align with host

Figure 1. Wood Mackenzie Analogues.

Figure 2. Volumes represent combined total of all existing oilfields with 50 million bbls or more of originally in place resources and reserves.

country national interest or investment thresholds of producing companies.

In other locations, new partnerships with leading operators and deployment of development practices already proven elsewhere could enhance recovery. The search for advantaged resources in existing fields will continue as stakeholders chase higher recovery factors which are potentially technically achievable. Exploration will continue to play a role.

Determining value in undrilled prospects

Existing fields will not fill every gap in meeting global oil and gas demand. Economics, location, and geopolitics will create barriers that leave a place for conventional exploration. Wood Mackenzie advances its analysis to meet this challenge by answering a key question: what might a prospect be worth if discovered and developed?

Valuations of producing assets have long been Wood Mackenzie’s core strength. The company now applies this asset valuation expertise to undrilled accumulations through Prospect Valuations work. The Prospect Valuations tool allows users to screen, benchmark, and value upcoming opportunities from an enhanced global dataset of mature, drill-ready prospects. It opens new options for users to understand competitor strategy, analyse internal portfolios, and evaluate opportunities.

Valuing prospects involves many unknowns, but our models use five connected components. These include estimating production profiles, well requirements, development solutions, capital expenditure and phasing, plus operating costs. Wood Mackenzie links these to its fiscal engine to build indicative models for each prospect. This provides the same financial metrics as typical commercial field valuations, including NPV, IRR, and cost/bbl measures.

Early analysis shows deep and ultra-deepwater projects offer the largest prizes in prospective resource and risked value. Latin America and Africa lead globally, particularly for oil prospects, whilst European and Asian exploration portfolios focus heavily on gas opportunities. The Majors and National Oil Companies continue to hold the largest share of volume and risked value worldwide.

Industry transformation through intelligent resource deployment

The upstream oil industry stands at a critical juncture where 1 trillion additional bbls await extraction from existing fields. Online fields decline whilst traditional exploration alone cannot bridge the substantial supply-demand gap projected through 2050. The industry has already discovered vast oilfields containing resources needed to meet much of this challenge.

The critical missing piece has been analytical tools to navigate these complex options effectively. Success depends on identifying which existing fields offer greatest upside potential, which prospects merit development investment, and how to benchmark performance against global best practices.

Wood Mackenzie’s AI-powered Analogues feature and Prospect Valuations toolkit provide these capabilities, eliminating human bias whilst leveraging comprehensive global datasets.

As the industry meets sustained oil demand whilst maintaining capital discipline and emissions management, success will depend not on discovering entirely new plays, but on intelligently deploying capital where it can deliver greatest impact. The resources exist, the technologies are proven, and the tools now exist to connect them strategically and efficiently.

Mark Kelly, head of digital and innovation at Bilfinger, UK, discusses how infrastructure is the key to the energy sector’s digitisation ambitions.

ecent advancements in technology have created a whole host of exciting opportunities within the energy sector that can revolutionise many of our on-site processes.

AI is one area where every industry is exploring its uses and we’re seeing first-hand the impact it’s starting to have across all of the industry segments we provide services to. When it comes to oil and gas, a large amount of data analytics is still done by people but there is potential for AI to support with this, particularly when it comes to site operations and maintenance.

This would involve integrating both current and new systems. Many oil and gas sites may still rely on systems that were built decades ago, which weren’t designed to share data with modern AI platforms but this doesn’t mean that they can’t. We’re still able to extract data from these legacy systems to help to unlock powerful insights that can drive efficiency improvements.

When combined they would be able to automatically detect faults on site, helping to improve safety and automate processes. Condition monitoring like this has existed for a number of years, but now with AI technologies we can further optimise processes and gain deeper insights into what the data we are seeing really means.

The possible applications for this are wide ranging. At its simplest, AI models could analyse data collected from sensors

and equipment to detect anomalies in areas like temperature or pressure that usually precede a mechanical breakdown. This predictive maintenance could identify on-site faults before they even occur – improving efficiency and reducing costs.

But there is the potential to take this even further. Digital twins are often misunderstood and misrepresented, but a

truly integrated digital twin built as a fully integrated model of a facility and all of its data points can be hugely powerful. Combining these systems with AI’s ability to adapt and learn in real time can help to create living models that mirror real world behaviour.

For instance, a refinery twin could simulate how changes in feedstock quality impact yield, emissions, or energy use. Engineers would be able to safely test different scenarios without changing their operations – saving time, money, and resources.

Another area in our industry where we’re seeing technology deployed is robotics. There are exciting developments when it comes to using machines in the field to perform tasks that would otherwise be dangerous for humans.

For example, we’ve used the G.E BIKE to help perform safety inspections for pressure vessels, a crucial task within our industry. By deploying technology for this, it eliminates the need for people to enter confined spaces to carry out these inspections, reducing the risk of accidents or exposure to harmful substances.

Across the North Sea, drones and automated subsea inspection vehicles are becoming common. They are allowing the teams to reach areas too dangerous or remote for people, performing a variety of tasks from inspecting flare stacks to carrying out underwater weld checks.

It’s clear that the ongoing digital revolution will bring a whole host of new benefits to the sector. But whether its robotics or AI, all these developments have something in common – they are powered by data. Take our G.E BIKE. If it’s to carry out on-site inspections, it needs to be programmed with precise inspection routines to ensure high levels of accuracy and consistency, which means having a reliable data localisation system in place.

If we’re to reap the rewards from these digital innovations, having the proper data infrastructure in place is crucial.

Building a solid data infrastructure

All digital technologies rely on the collection, processing, and sharing of vast amounts of data. In our sector, this typically involves using tools like smart meters, sensors, and grid systems to collect information like equipment performance as well as energy consumption and flow.

The first step to building this solid data infrastructure for new technologies like AI to use is to standardise data archives. This means ensuring all information follows the same formats and protocols so that it can be utilised across different systems and organisations.

As with all data, it’s also essential to put measures in place to protect any sensitive data and comply with privacy regulations. There are currently more devices connected than ever before across our different supply chains. It’s never been more important for technology networks to be protected from intrusion in order for businesses to maintain safety and trust with their stakeholders.

And with new technologies only increasing the capacity of what we can do, any robust data

Figure 1. Predictive maintenance can identify on-site faults before they even occur.

Figure 2. Recent advancements in technology can revolutionise many on-site processes in the energy sector.

infrastructure will also need to be scalable. This means building systems that can handle increasing volumes of data as the industry, and its technology, continues to evolve.

It also means ensuring any data infrastructure is built on secure, high-speed connectivity. Many operators use cloud platforms and computing to process data locally before syncing it with central systems. Reliable connectivity is therefore critical in allowing insights to be delivered instantly, especially in remote offshore environments where bandwidth may be limited.

We shouldn’t underestimate how much of the data we need already exists. For years industrial systems have been collecting and collating information on operational infrastructure.

Introducing AI analytics doesn’t mean re-inventing the wheel, as the existing data, sensors, and infrastructure already provides a perfectly valid starting point.

But building this strong infrastructure is not enough on its own. Technologies may be powered on data but they still rely on people to use them properly. The most effective use of AI comes from collaboration, not replacement. This also applies to robotics with uptake of co-bots increasing across multiple sectors.

The experience and specialist knowledge of engineers is still crucial, and equipping them with the skills to use this technology properly will help ensure new innovations are grounded in a realworld understanding of operational safety.

Upskilling people

This is one area where our industry currently faces a significant challenge.

Research shows that roughly 21 million working-age adults in the UK can’t perform the full set of tasks outlined in the

skills gap is felt across all sectors, including oil and gas, and has shown no signs of improving in recent years.

As more new digital innovations emerge, the demand for digitally skilled workers will only grow meaning it’s essential that we act now. This is where upskilling programmes can make all the difference.

There are many ways that we can – as organisations – look to achieve this. Simple online guides and video tutorials can be produced to teach employees how to carry out everyday tasks using systems like Microsoft CoPilot and ChatGPT.

Alongside this, offering comprehensive training courses in areas like data analytics, cybersecurity, and cloud computing, and investing in the digital education of people in our sector through new data or technology apprenticeships can go a long way in helping to address this gap.

Collaboration between industry, education bodies, and government can play a huge role in driving this. Working with institutions like technical colleges, energy companies can design educational programmes that combine traditional engineering with digital skills. This will be critical in future-proofing our workforce and bringing through the next generation of talent within the industry.

There is a wealth of benefits to be had within the oil and gas sector as more innovative technologies continue to be developed. If used properly our industry can make huge strides in making operations safer and more efficient than ever before.

But for the industry to harness the full potential of this digital transformation that we’re going through, it’s essential that we make sure both our data and our people are ready for this change.

Reference

Designing risk out of digital pipelines

Hector Perez, Head of Strategy for Black & Veatch’s Industrial Cybersecurity practice, talks to Elizabeth Corner about digital twins, predictive analytics, and emerging AI tools, highlighting how siloed data, legacy systems, and unmanaged digital risk can undermine operational gains if security is treated as an afterthought.

We cover:

• How pipeline operators are moving from reactive maintenance to predictive maintenance.

• Digitally enabled asset strategies.

• Why cybersecurity must be embedded from the outset.

Graham Faiz, Head of Digital Energy at DNV, explores the risks that exist in offshore safety mechanisms and proposes a template for systemic AI safety.

he rapid and recent advancements in artificial intelligence (AI) have substantially increased its potential use cases in the offshore energy industry.

In tandem, the risks associated with using AI have grown, and the mechanisms in place to ensure the safe use of AI are now struggling to keep up.

According to DNV’s Energy Industry Insights 2025 report,1 60% of the energy sector indicated that they would use AI in their operations in the year ahead, up from 47% the previous year.

By its very nature AI is disruptive, but its rapid development and ease of accessibility present regulators with a real challenge. Overlooking the complexity of AI-enabled systems and their interactions can lead to failures with severe consequences.

As the broader adoption of AI tools and technologies sweeps the industry, the likelihood of systemic failures occurring ramps up significantly. To maintain acceptable levels of residual risk, the sector must transition from a reactive stance to a proactive and systematic approach to AI safety.

Cyberattacks and AI-driven equipment failures are already on the radar of offshore operators, but we must not allow smaller, less detectable, systemic risks to slip through the cracks as personnel integrate AI into their daily tasks.

These risks, born of unpredictable interactions between humans and AI, could pose the greatest threat to operational safety.

Consider, for example, an engineer using a generative AI model to draft standard operating procedures for new equipment. How can the industry ensure that such content maintains the same level of safety assurance as a traditionally authored procedure?

A recommended practice for AI

To promote the safe implementation of AI, DNV has developed a Recommended Practice (RP) for the assurance of AI-enabled systems (DNV-RP-0671). This framework provides guidance on how to evaluate whether AI-enabled systems are trustworthy and responsibly managed throughout their lifecycle.

Central to the RP is the concept of aligning assurance with stakeholder interests, formalised as system claims, which are clear, testable statements about what an AI-enabled system is expected

to do and the conditions under which it will perform safely and reliably. Confidence in these claims is built through structured, evidence-based logic.

Assurance cases set out the rationale and proof supporting each claim, using facts, assumptions and sub-claims to establish justified confidence in a system’s performance.

By taking a systems perspective, we can ensure that emergent behaviours and complex interactions between components and their environment are understood, while a riskbased approach prioritises assurance activities according to any potential consequences and uncertainties.

In managing the increasing complexity of AI use cases in the energy industry, DNV-RP-0671 promotes modularity. This involves breaking systems into manageable parts, each with its own assurance module, and adopting a lifecycle perspective that recognises the evolving nature of AI evolves over time and use. Assurance activities must therefore remain dynamic, reflecting the system’s current state and operational context.

To further address the unseen risks of AI in the sector, DNV has proposed a systemic safety case framework that incorporate safety engineering principles and AI assurance across the entire system lifecycle.

The case for safety cases

The energy industry must anticipate the potential pitfalls of using AI instead of merely responding to emerging vulnerabilities.

For the causes of AI associated safety risks to be addressed, knowledge of how a system may become unsafe must be established beforehand.

To continue operating, offshore oil and gas installation duty holders are required to prove on an ongoing basis that they can effectively control and mitigate major accident risks.

In doing this, operators must submit safety cases, which are structured arguments supported by evidence, to justify that a system is acceptably safe for a specific application. These cases demonstrate that major hazards have been identified, and appropriate controls provided.

A similar approach is now emerging in the frontier AI space. The concept of an AI safety case, which provides structured assurance of safe design, deployment, and operation, is gaining traction to ensure responsible innovation.

Although the offshore energy and frontier AI sectors recognise safety cases as an appropriate assurance mechanism, their scope is often limited to the requirements put on them by regulators and society at large. To meaningfully address the risks of AI applications in the energy sector, specific safety case templates must be developed to consider domain and technology-specific interactions that may lead to the emergence of new or hidden safety hazards.

A case template to address systemic AI safety risk

DNV’s new safety case template was devised to support the increasing adoption of AI in safety-critical operations across the offshore energy sector.

The template safety case is based on the framework presented in DNV-RP-0671; the Safer Complex Systems Framework from the University of York, which has emerged from work on relevant work on ISO standards in the automotive industry; and finally, some related safety case activity for frontier AI that has originated from the AI Safety Institute. DNV’s adapted approach has been developed for a specific industrial application of AI, namely the risks associated with Large Language Modelpowered (LLM) health and safety management support tools.

By combining these approaches, we can enable: Ì Sources of emerging safety risks to be identified.

Ì Safety controls to be assessed.

Ì System safety claims to be structured.

Ì The safety case to be updated and audited.

The template has also been designed to be repeated and replicated for other complexity-driven challenges.

The safety case uses the concept of claims and sub-claims to break down the question of system safety into smaller, verifiable components. The top claim – that the AI-enabled system is safe in its intended context – cannot be proven directly. Instead, it is broken down into lower-level claims that address design-time and operation-time controls, each supported by specific arguments, assumptions, and evidence.

These claims are tested through system trials, independent assurance, and third-party certification, which verify an organisation’s ability to manage AI responsibly.

In practice, AI prompt engineering, adversarial testing and other similar techniques will help to strengthen the robustness of the assurance.

During the operational phase, the template addresses the human and procedural factors that influence safe system use. Controls such as user training, ongoing competence checks and integration of feedback from real-world incidents are vital to maintaining reliability over time.

Continuous assurance mechanisms, such as automated logging and anomaly detection, help ensure that evolving user behaviours or system updates do not introduce new risks.

What makes this safety case approach particularly robust is its transparency and traceability. Each claim is linked directly to evidence and the reasoning can be independently reviewed, replicated and refined as the system evolves. This modular design means that the assurance can mature alongside the AI system itself, closing knowledge gaps and incorporating lessons learned throughout its lifecycle.

By applying this structured, evidence-based approach, DNV’s safety case template provides a practical method for demonstrating how AI tools, including LLM-powered decision support systems, can be deployed safely in complex offshore environments.

From unseen risk to assured resilience

AI is transforming industries around the world, and the offshore energy sector is no different. It is poised to create new efficiencies, insights and decision-making capabilities, but we must look before we leap.

As AI becomes embedded in critical systems, the industry needs to take responsibility for how it is used and ensure that assurance and safety are not compromised by innovation. The hidden risks that AI could introduce therefore demand a structured and forward-looking response.

The proposed systemic AI safety case template integrates safety assurance frameworks to help outline and address the unique and complex challenges of AI in this area.

To build trust in using AI, the industry must assure it with the same rigour and discipline that have long underpinned safety in the energy industry. DNV’s RP and safety case template can provide a practical framework for demonstrating that AI-enabled systems are safe, reliable, and fit for purpose.

Reference

1. Energy Industry Insights 2025: Short-Term Volatility, Long-Term Optimism: https://www.dnv.com/energy/insights/energy-industry-insights/short-termvolatility-long-term-optimism/

Figure 1. The rapid advancement of AI has substantially increased how it can be used in the offshore energy industry, but the risks associated with its use have grown in tandem.

Figure 2. According to DNV research, 60% of the energy sector plans to use AI in their operations in the year ahead.

Hani Almufti, Cogbill Construction, discusses corrosion under pipe supports (CUPS) on FPSOs, focusing on the challenges, mechanisms, and a novel mitigation solution.

orrosion under pipe supports (CUPS) on FPSOs is aggravated by warm, chloride-rich atmospheres with long time-of-wetness and hard-to-reach interfaces, accelerating crevice, under-deposit, galvanic, pitting, and microbiologically influenced corrosion (MIC) damage. This article presents the RedLineIPS SmartPad: a fully non-metallic fibre-reinforced polymer (FRP) saddle with

Figure 1. Illustration of FPSO vessel – topsides with processing modules, helideck, flare, and lifeboats on a single hull for offshore production, storage, and offloading (source: Cogbill).

a bonded closed-cell gasket, secured by fibre-reinforced thermoplastic straps. It installs without the need for hot work (no welding, drilling, cutting, grinding, etc.) or the use of epoxy, and is intentionally removable for quick visual inspection. The sealed, non-wicking interface and dielectric load path eliminate electrolyte retention and metal-to-metal continuity – the prerequisites for crevice/galvanic attack –while avoiding coating damage. Unlike adhesive-bonded FRP wear pads, SmartPads are banded, enabling immediate open-and-reseal inspections with no adhesive cure windows. Operationally, per-support inspection time can drop from approximately 1 - 2 h to <10 min (access-dependent), reducing labour and work-at-height (WAH) exposure.

CUPS is a hidden threat on FPSOs: attack starts at the pipe/support contact – hard to see and reach – so wall loss can progress until alarms or intrusive inspections catch it late. Warm, chloride-rich atmospheres with long time-ofwetness accelerate the electrochemistry, while congestion and work-at-height (WAH) constraints make inspection costly.

Conventional fixes – welded pads, metallic clamps, or adhesive-bonded FRP – often damage coatings, create crevices, preserve electrical continuity, or add hot work/ cure windows. The practical gap is how to both prevent CUPS and verify condition quickly in service.

This article summarises the key CUPS mechanisms on FPSOs (crevice/differential aeration, under-deposit, galvanic, pitting, MIC, and, where relevant stress corrosion cracking [SCC]); explains why warm climates intensify them; and introduces the RedLineIPS SmartPad – an allnon-metallic, sealed, dielectric, cold-work support that is intentionally removable for direct visual inspection. Scope is corrosion-focused; installation/inspection practicality is treated as an enabler for at scale deployment.

FPSO fundamentals

An FPSO produces, processes, stores, and offloads hydrocarbons on a single hull. Fluids arrive via flexible risers to a weathervaning turret or spread moorings. Piping spans small-bore instruments to large crude/gas/water lines. Carbon steel dominates; external protection is typically multicoat epoxy/urethane, with thermally sprayed aluminum (TSA) + sealer on high-exposure items. Supports –welded shoes/ stools, split clamps, guides/ stops, U-bolts with liners, wear pads – are densely packed in racks and under weather covers where ventilation is low and salt wetting is frequent. Why do supports matter? They carry sustained/transient loads while accommodating thermal growth and hull motions. Micro-slip at the contact can fret coatings/oxides, exposing steel. The shaded interface traps salt and condensate, forming tight, damp crevices. A small coating holiday under a support becomes a tiny anode coupled through electrolyte to a much larger cathode (surrounding steel), accelerating loss via the arearatio effect. Hidden geometry and elevation/insulation impede access, so CUPS can progress between inspection cycles.

Corrosive environment for FPSO topsides

Macro environment

FPSO decks live in salty, humid air with strong sunlight and constant wet-dry cycling. Seasalt deposits are hygroscopic –they pull moisture from the air – so surfaces can stay effectively

Figure 2. Rust halo at the pipe–saddle contact – an indicator of CUPS on offshore topsides; trapped salt moisture under the support initiates hidden wall loss (source: Cogbill).

Figure 3. SmartPad System – SmartBands (anti-backdrive buckles), bonded closed-cell gasket, and FRP SmartPad saddle – an all-non-metallic assembly that seals the pipe–pad interface for quick lift–look–reband inspections (source: Cogbill).

‘wet’ even without rain. Heat speeds corrosion reactions and ultraviolet (UV) light ages coatings, making them more permeable to water and ions.

At the pipe/support contact

The narrow, shaded gap under a support location behaves like a crevice. It traps moisture, concentrates chlorides as it dries, and becomes oxygen-poor. That chemistry turns the hidden zone into the anodic site where steel dissolves, while nearby exposed steel acts as the cathode. Wicking, salt build-up, and local acidification keep the crevice active until it is opened and dried, leading to localised thinning under supports.

Warm vs cold seas

Tropical regions (e.g. West Africa, Brazil, Southeast Asia, the Arabian Gulf/Red Sea) are harsher: higher temperatures, more frequent salt deliquescence (longer ‘time of wetness’), and more active microbiology. Net result: crevice, pitting, MIC, and galvanic processes start sooner and run longer than in temperate basins.

Operations that make it worse

Common FPSO conditions keep supports wet and salty: condensation on cold lines, seawater washdowns and spray, drainage toward supports, shaded/low-airflow racks, wick-prone insulation terminations, small leaks and residues, debris accumulation, and motions that rub away coatings. Weathervaning can load one side with more salt. Bottom line: longer wetness, higher chloride, and low oxygen – the perfect mix for CUPS.

CUPS mechanisms on FPSOs

Ì Crevice corrosion/differential aeration: moisture trapped in a tight gap becomes oxygen-starved, turning the hidden area into the active corrosion site until the crevice is opened and dried.

Ì Galvanic effects: if a small coating defect under a pad stays wet and is electrically connected to the larger surrounding steel, the small area corrodes faster (area-ratio effect) – even with ‘similar’ metals when oxygen levels differ.

Ì Under-deposit corrosion: rust, salts, paint chips, and grime hold brine and block oxygen, creating micro-crevices where chlorides concentrate and pH drops, accelerating local attack.

Ì Pitting corrosion: chloride-rich films locally break down protective oxides; warm temperatures make pits start and grow more readily, especially in shielded gaps.

Ì Microbiologically influenced corrosion (MIC): biofilms alter local chemistry; sulfate-reducers and other microbes can create conditions that favour localised corrosion in damp crevices.

Ì Stress corrosion cracking (SCC): tensile stresses plus aggressive local chemistry (chloride or sulfide environments) can nucleate and grow cracks from pits or weld features.

Ì Fretting-assisted corrosion: small motions from thermal growth and hull movement rub away

Figure 5. SmartTool band-tensioning system for SmartPad installation (left → right): mechanical SmartTool with precision torque setting, pneumatic SmartTool for rapid, repeatable mass installation, and manual hand tool for low-access or spot work (source: Cogbill Construction/RedLineIPS).

Figure 6. SmartPad System installed on topside piping – FRP saddles with composite bands create a sealed, dielectric interface at supports, enabling quick cold-work lift–look–re-band inspections (source: Cogbill).

Figure 4. A water droplet on the HydroSeal gasket encapsulates its core promise: durable, leak-free sealing in demanding conditions.

coatings/oxides and generate debris that retains brine, accelerating the mechanisms above.

SmartPad system: non-metallic architecture tailored for FPSOs

FRP saddle (wear pad)

A FRP saddle – continuous glass fibres in a corrosionresistant, UV-stabilised resin – is profiled to the pipe outside diameter (OD). The laminate is electrically non-conductive and chemically resistant to marine atmospheres and common topsides contaminants, providing dielectric isolation at the pipe/support interface.

Why it works on FPSOs

Ì Load distribution, coating care: the contoured, pipematched curvature spreads bearing load; smooth, radiused contact surfaces are low-abrasion to sound coatings.

Ì ‘Stay-put’ geometry: recessed band grooves and chamfered edges resist migration and ease alignment/ removal during inspection.

Ì Weathering resistance: marine-grade resin systems with UV stabilisers limit embrittlement and colour change in hot, high-UV service.

Ì Dielectric interface: non-metallic contact breaks metalto-metal paths at the support, a prerequisite for galvanic CUPS.

Options include coverage angle/length and laminate thickness to suit pipe size, load path, and inspection access.

Closed-cell elastomeric gasket (HydroSeal concept)

A factory-bonded, closed-cell elastomer between the FRP saddle and pipe coating creates a continuous, conformal, non-wicking seal. Under band preload it fills coating texture without capillary paths.

Ì Watertight (National Electrical Manufacturers Association [NEMA] Type 4): the HydroSeal gasket itself is manufacturer-rated to NEMA Type 4. When compressed approximately 30% with the SmartTool (and aided by pipe deadweight), the pipe–pad interface provides an equivalent level of splash/spray exclusion.

Ì Holds preload: low compression set preserves contact pressure through thermal/vibration cycles and re-seals after cut-and-re-band inspections.

Ì Bonded to the saddle: maintains a continuous sealing surface and eliminates additional crevice edges.

Ì Materials: EPDM (hot water/brine), silicone (high-temp/ UV), PTFE-faced (chemical resistance/low stick-slip); grade and hardness per project service.

Fibre-reinforced thermoplastic straps and buckles

Its composition includes long-strand, fibre-reinforced thermoplastic straps (aligned fibres for higher strength vs chopped) with radiused, smooth inner faces and polymer buckles provide fully dielectric clamping without metal in the load path and avoid bruising sound coatings.

Key features include:

Ì Locking geometry: square-tooth, anti-backdrive buckles mechanically lock the band and resist loosening under vibration/thermal cycling; clamp load is maintained when installed to spec.

Ì Inspection and reuse: for visual checks, cut straps, lift pad, inspect/clean/dry, then reuse the same saddle and

buckles with new band stock and re-tension to spec. The cycle takes minutes, requires no hot work or cure windows, and keeps per-support inspection cost low.

SmartTool and installation method

A compact SmartTool (manual or pneumatic) tensions the bands to a preset target and shears the tail flush, leaving no sharp edges near the coating. No hot work, drilling, or adhesives are required. On ‘live’ lines, installation is typically permissible under site permits because there is no heat source and no cure window; follow site isolation and work-atheight controls.

Installation steps

Clean/dry the contact area; position the FRP saddle; route bands through the buckles; tension to the specified setting; verify uniform gasket compression and alignment in the band grooves.

Inspection/removal

Cut the bands, lift the saddle, inspect/clean/dry, then thread fresh bands and re-tension. The expose/inspect/re-band cycle is completed in minutes, enabling direct visual checks in congested or elevated modules.

FPSO-focused benefits (corrosion and operations)

Corrosion control at the hotspot

Ì A sealed pipe-pad interface (NEMA-4 watertight seal when the gasket is compressed) keeps water out of the pipe/pad contact surface, even on windward/splash-exposed faces – cutting crevice, under-deposit (UDC), MIC, and chloride pitting.

Ì A fully dielectric load path (FRP saddle + closed-cell gasket + composite bands) breaks metal-to-metal continuity to support steel – reducing galvanic couples, including differential-aeration effects.

Ì The non-wicking, closed-cell gasket conforms to imperfect or previously coated surfaces and cushions micro-motion –limiting fretting and the debris/brine nests that feed UDC.

Built for FPSO exposure

Ì Performs on windward racks, washdown/splash zones, and sweating cold services, keeping the gap dry where salt, fire-water testing, and condensation are routine.

Ì UV-stabilised composites and gasket options resist chalking/embrittlement on open decks; broad service window (approximately -60˚F to 400˚F/-51˚C to 204˚C) covers chilled, ambient, and hot duties.

Mechanical integrity and coating care

Contoured FRP saddle eliminates point/line loading and protects coatings with smooth, radiused contact. Recessed strap grooves positively locate bands so vibration/hull motions cannot ‘walk’ them; clamp force stays on the saddle, off the paint – preventing seal loss and pad drop-off. Long-strand glass-fibre bands with square-tooth, anti-backdrive buckles hold preload through thermal/vibration cycles.

Installation, inspection, and operations

Ì Epoxy-free, cold-work install on live lines: no welding/ drilling, no cure windows, minimal clearance (approximately 1 - 2 in.), and no hot work permits.

Ì Preset SmartTool delivers repeatable preload.

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Ì Rapid ‘lift-look-re-band’ visual inspections in minutes – practical in congested racks and at height – so issues are found early without heavy NDT such as UT, electromagnetic acoustic transducer (EMAT), and radiographic testing (RT).

Safety and EHS

Fewer hot work tasks/solvents, shorter jobs at height, and fewer confined-space NDT trips reduce exposure hours and permitting complexity.

Integration and assurance

Ì Retrofit-friendly (start with high-risk circuits, expand by RBI); newbuild-ready (specify in standards/isometrics).

Ì Compatible with site cathodic protection (CP)/earthing philosophies; verify isolation with a quick resistance check.

Ì Uses proven FRP/elastomers/composites; gasket chemistries (EPDM, silicone, PTFE-faced) match media and temperature.

Total cost of ownership (TCO)

Ì Minutes-per-support installs vs hours for welded/epoxied options; fewer permits and no specialist trades.

Ì Lower inspection burden (more visuals, less scaffolding/ NDT), minimal coating touch-up, reusable hardware (replace only low-cost band stock), and faster, phased campaigns – delivering sustained OPEX and risk reduction over vessel life.

Installation and inspection on FPSOs

Cold-work install on live lines; typical install/reinstall take approximately 2 - 5 min per support (access-dependent). For

inspection, cut bands, lift saddle, clean/dry, refit saddle/ buckles, and re-band to spec. This expose/inspect/ re-seal cycle requires no hot work or cure window.

Conclusions

On FPSOs, CUPS stems from retained electrolyte, oxygen restriction, galvanic continuity, and debris-held crevices in warm, chloride-rich atmospheres. A non-metallic, sealed pipe/support interface interrupts these drivers. The SmartPad System – FRP saddle, closed-cell gasket, and fibre-reinforced thermoplastic straps – breaks metal-to-metal paths, blocks persistent crevice films, and can be opened and re-sealed in minutes for direct visual inspection. This is especially valuable in warmwater regions where heat and humidity accelerate corrosion and salt deliquescence. Retrofit-friendly and requiring no hot work or cure windows, it reduces inspection time and cost. In sum, sealed, dielectric, removable supports provide a targeted barrier to FPSO CUPS and merit specification, subject to checks on coating condition, materials compatibility, and support duties.

About the author

Hani Almufti is Engineer and Manager of Strategic Development at Cogbill Construction (RedLineIPS). With 15+ years in pipe supports – ten focused on offshore – he specialises in CUPS and the performance of FRP/ composite and metallic supports. He leads product strategy and materials selection, aiming to cut risk, vibration, and lifecycle cost.

A podcast series for professionals in the downstream refining, petrochemical, and gas processing industries

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Sheldrake, Veolia

– Water Tech, addresses securing offshore resilience with smarter water treatment.

he world still relies heavily on oil, even as alternative energy sources grow in popularity. Building sustainable, hydrocarbon-free energy sources will take time to reach a global scale. In the meantime, offshore operators face a dual responsibility: to make current production as efficient and low-impact as possible, and prepare assets that use less carbon to create an ecological transformation.

When people think about offshore oil production, they often picture the drilling rigs and the massive FPSOs that serve as floating factories at sea. But the real lifeblood of offshore production is the treated seawater being pumped back in.

For every barrel of crude produced, site operators may need to inject a barrel of water. That water keeps the reservoir pressure steady, flushes hydrocarbons toward collection wells and

ultimately ensures a project delivers its promised volumes. But seawater is far from a benign medium. Untreated, it brings sulphates that scale and clog the reservoir, oxygen that corrodes steel, and bacteria that can sour an entire field. Getting water treatment right is the difference between a smoothly operating FPSO and one plagued with costly downtime.

Onshore, space and weight are rarely limiting factors. Offshore, every tonne of topside equipment competes for a finite footprint, and every cubic metre of volume has to be engineered around dynamic motions at sea.

Water treatment systems are no exception. They must be compact, robust and able to withstand motion, vibration

and the corrosive marine environment. Desalination is more scalable onshore. Seawater reverse osmosis (SWRO) is vital offshore, but its role is producing potable water for crews and small process volumes, such as basic sediment and water control of crude oil. These units handle flows on the order of hundreds of cubic metres per day, typically about one-tenth the volumes treated by sulphate removal systems (SRS) for injection. Onshore, however, SWRO plants scale up dramatically, with commercial facilities treating orders of magnitude more seawater than any offshore system. Over the next five years, the global desalination market is expected to grow to US$97 billion, driven primarily by the Middle East, Pacific Asia and some countries in Europe.

Sulphate removal systems (SRS) are an additional step, stripping sulphates from seawater before injection to prevent barium and strontium sulphate scaling in the reservoir. Together, these processes protect infrastructure, safeguard reservoir performance, and keep production flowing.

But successful design doesn’t stop with membranes and pumps. Systems must also be arranged within tight footprints, often shoehorned between cranes, risers, and flare stacks. Too tall a structure risks obstructing crane movement. Too heavy a system threatens vessel stability. The balance between process performance and practical engineering is constant, and it shapes every project offshore.

Lessons from global FPSOs

Over the past three decades, sulphate removal and desalination systems have been deployed on FPSOs across Angola, Brazil, the Gulf of Mexico, Guyana, and the North Sea. Each project comes with its own challenges, including wave motions and space constraints, but the principle remains the same: reliable water treatment equals reliable oil production.

Consider projects offshore Brazil, where massive pre-salt FPSOs such as Marlim 1 require sulphate removal modules capable of treating more than 60 000 m3/d of seawater. Or the developments in Guyana, where SRP and SWRO modules for the Liza field FPSOs are helping operators manage some of the fastest-growing offshore fields in the world. These are proven systems underpinning multi-billion-dollar assets.

In Angola, projects such as Pazflor and Clov demonstrate how sulphate removal has become standard practice. Pazflor alone incorporates both SRP and SWRO trains to support an FPSO producing over 300 000 bpd.

A recent deployment in Brazil’s Santos Basin illustrates how these technologies continue to evolve. For two new pre -salt FPSOs – Petrobras’ P84 and P85 – advanced seawater treatment systems will be installed. They feature ultrafiltration and nanofiltration membranes capable of treating nearly 2000 m3/h of seawater to remove sulphates and protect reservoir integrity while enhancing oil recovery

In the North Sea, earlier projects such as Buzzard and Tiffany showed how sulphate removal was first integrated into offshore operations decades ago. These facilities helped establish a playbook that has since been scaled up for today’s megaprojects. They also underscore the evolution of technology – from early cartridge-based filtration to today’s ZeeWeed™ Ultrafiltration and nanofiltration membranes that can deliver higher throughput with lower energy requirements.

Taken together, these examples show the diversity of conditions and the adaptability of water treatment

Figure 1. Integrated SWT process modules (©Veolia).

Figure 2. Integrated SWT process modules (©Veolia).

Figure 3. Sulphate removal membrane rack (©Veolia).

technology. Whether it’s the pre-salt reservoirs of Brazil, the deepwater fields of West Africa, or the mature assets of the North Sea, one principle is universal: Without reliable seawater treatment, offshore oil production cannot succeed.

Not every company entering the offshore market has grasped the complexity. Some onshore specialists have underestimated the realities of offshore design and operation, only to discover too late that equipment sized for land cannot simply be placed on a floating production unit. Experience matters, and the track record of successful deployments is one of the clearest differentiators in this space.

Economics of injection water

Many reservoirs are so sensitive that a barrel of water injected equates almost directly to a barrel of oil produced. Reduce injection rates, and production falls sharply. For a project with billions of dollars invested, even small deviations from injection capacity can erode the business case.

That’s why operators scrutinise injection system uptime and capacity so closely. If a sulphate removal unit underperforms, the reservoir may suffer irreversible damage. Conversely, a system that delivers consistent volumes at design quality can extend a field’s productive life and maximise return on investment.

The economics extend beyond the operator. Host nations rely on royalties, taxes, and production-sharing agreements tied to output. Maximising oil recovery from each field supports national revenues, meaning effective water treatment benefits governments as much as oil companies. Water treatment is a cornerstone of project economics. In regions where hydrocarbon revenues fund infrastructure and social programmes, the ripple effects of water treatment stretch well beyond the platform itself.

Beyond the installation: lifecycle support

Designing and building a system is only half the job. Offshore water treatment plants run for decades, and their performance determines how much crude ultimately gets recovered. That’s why services, monitoring and training are every bit as critical as the membranes and pumps themselves.

Digital monitoring platforms now allow operators to track key parameters in real time, flagging deviations before they escalate into downtime. Chemical optimisation programmes help reduce both consumption and carbon footprint, cutting the volumes that need to be shipped hundreds of kilometres offshore.

Lifecycle support also includes spares management, predictive maintenance and quick-response engineering. A well-stocked offshore warehouse of filters, membranes and pumps can mean the difference between an hours-long fix and weeks of production loss while waiting for parts.

Equally important is operational knowledge transfer. As experienced engineers retire, the gap is increasingly filled by younger crews. Structured training programmes and knowledge databases are now used offshore to ensure continuity of expertise.

This lifecycle approach reflects the reality offshore: uptime is everything. A day lost to equipment failure or

misoperation can cost millions in deferred production. Robust service support keeps systems running at design capacity, protecting both revenue and reservoir integrity.

Sustainability and transformation offshore

Offshore operators face the dual challenge of maximising production while reducing environmental impact. Water treatment technologies are central to that balance.

One tangible example is filter cartridges. Our research estimates that nearly 900 000 plastic cartridges are consumed annually, generating more than 1000 t of waste. By replacing disposable plastic filters with metallic alternatives that can be ultrasonically cleaned and reused, operators can cut landfill waste and shrink the carbon footprint associated with manufacturing and transport. Recycling programmes capture what cannot be eliminated, closing the loop and moving the industry toward zero waste.

Chemical consumption is another frontier. By optimising chemical blends and sourcing options, operators can reduce volumes transported offshore while lowering the overall carbon intensity of operations. Small changes at the molecular level can add up to meaningful environmental benefits across global fleets of FPSOs. Some operators are already trialing biocide alternatives and lower-dosage antiscalants that maintain system integrity while cutting environmental load.

Beyond waste and chemical reduction, energy efficiency is the next horizon. Optimising plant design can eliminate entire sets of pumps, reducing power demand and lowering CO 2 emissions from onboard gas turbines. In regions where offshore grids connect to onshore renewables, future FPSOs may even draw supplemental power from wind or solar farms.

Medium-term goals include integrating carbon capture technologies to extend the viable life of FPSOs under tightening emissions targets. Concepts for bolt-on carbon capture units are advancing, with water treatment plants serving as natural integration points for CO 2 removal given their pumping infrastructure and process synergies.

On the long-term horizon, operators are exploring hybrid solutions such as floating wind turbines coupled with desalination units, and even the conversion of retired offshore structures into green hydrogen production hubs. Early pilots show how desalinated water from offshore wind-powered systems can feed electrolysers to generate hydrogen, bringing water treatment into the centre of the energy transition story.

The progression is clear: practical sustainability today, transitional technologies tomorrow and fully renewable offshore systems in the future. Water treatment will play a role at every stage.

Water treatment used to be seen as a supporting utility – a necessary but secondary function to drilling and production. That perception has shifted. Desalination and sulphate removal are now strategic enablers of offshore resilience, ensuring uptime, protecting reservoirs and reducing environmental footprint.

As offshore production continues to push into deeper waters and more complex reservoirs, the stakes around water treatment will only grow. The lesson for operators is to consider more than just today’s performance. Securing tomorrow’s energy supply while building a bridge toward a lower-carbon future is essential.

Kleopatra Kyrimi, Sarens Group Marketing & Communications Manager, Sarens, Spain, discusses how Europe is responding to geopolitical disruptions in gas supply by accelerating the energy transition, investing in domestic gas production and cleaner alternatives, and relying on logistics and heavy-lifting operations to ensure energy security and infrastructure development.

he last few years have presented a genuine challenge for the global energy sector. It is important to remember that until just a few months ago, Europe was heavily dependent on the supply of Russian gas, which was vital for, among other things, ensuring electricity production across the continent and heating homes. Due to current geopolitics, this is no longer possible.

Europe has reacted in time to gradually reduce the reliance on gas in its energy mix, to such an extent that renewable sources now account for almost half of all energy production on the continent. Considered by many to be the least polluting alternative among those involving fuel combustion, gas

nonetheless continues to hold significant weight in the mix: it is estimated that approximately 5% of all energy produced in our continent still depends on this source.

Undoubtedly, the global geopolitical situation has had a very significant impact on the worldwide energy sector. Not only

due to the need to accelerate the energy transition towards less polluting sources, but also by triggering a major paradigm shift regarding the model of industrialisation and grid infrastructure. It is estimated that a 75% reduction in natural gas trade originating from Russia has accelerated the search for other sources. The US, Qatar, and Algeria are just some of the countries with which various agreements have been reached for the import of LNG. Once regasified at terminals – we have examples of this in countries like Spain, Italy, and Germany – it can be used to cover part of our continent’s energy needs.

In search of new alternatives to reduce gas importation

However, there is no doubt that importing gas extracted outside of Europe is not the most efficient option. For this reason, in recent years, prospecting efforts have been redoubled to increase gas production without needing to purchase it from third countries, thus avoiding the economic impact of price volatility and import/export tariffs. But for this to happen, significant investments are required to facilitate true energy independence.

Examples like the refurbishment of the Níord platform to extend its lifespan and access new gas and condensate reserves in the Norwegian Sea, or the discovery of new fields in Lofn and Langemann, lead to optimism in the sector. These developments position Norway as a true European gas production ‘hub’, after the country reached new annual gas production records, with over 124 billion m3 commercialised last year.

As mentioned earlier, investments to boost European energy independence are of great importance. The best example illustrating this need and its impact on the sector is the Valhall PWP-Fenris project, also in the North Sea. This project required an economic injection of 50 billion Norwegian kroner, equivalent to more than €4.2 million euros, to facilitate the exploitation of new reserves estimated at over 230 million boe. In other words, this field will have a production capacity of more than 500 million boe when it becomes operational in 3Q27.

These types of projects, which are of crucial importance not only for the European energy sector but also for the continent’s economy, are usually valued once they become operational. However, for these projects to reach the exploitation stage, significant logistical and construction work is necessary, which sometimes requires years of coordination between component manufacturers, heavy lifting companies collaborating in the assembly process, and specialists who transport the already assembled components, often weighing thousands of tonnes, to their final location.

The importance of logistics in ensuring energy supply

These tasks are much more complex than they might seem at first glance. In the case of Valhall PWP-Fenris, for example, it was necessary to mobilise more than 55 cargo trailers with equipment to carry out the first load-out tasks of a 11 500 t jacket at the Aker Solutions plant in Verdal, Norway. To simply understand this magnitude, the jacket was over 118 m tall, which is twice the height of the Statue of Liberty in New York, or practically the entire length of an elite football pitch.

As mentioned earlier, these types of projects are highly complex. To move components of this size and weight, it is necessary to have extremely high technical qualification and the necessary machinery. It must always be borne in mind that any minimal error can lead not only to significant material

Figure 1. 11 500 t jacket that was loaded-out in Verdal, Norway, for the Valhall PWP-Fenris project.

Figure 2. Sarens’ crew that was involved in the load-out of the jacket in the Valhall PWP-Fenris project, including a female SPMT (Self-Propelled Modular Trailer) operator.

Figure 3. The 11 500 t jacket, once loaded onto the barge responsible for its transport in the PWP-Fenris project in Verdal, Norway.

damage but also to delays in the execution of other logistical tasks and major economic losses. In the case of Valhall PWP-Fenris, to continue with the same example, it was necessary to mobilise specialised machinery, including Self-Propelled Modular Transporters (SPMTs), which are essential for transporting these types of loads with maximum guarantees. In this specific case, 354 axle lines of SPMTs were used, attesting to the significant magnitude of the transported object. In the coming months, the project’s topside, with an estimated weight of 18 800 t, will also be transported. This is practically double the weight of the Eiffel Tower in Paris, or the equivalent of over 3100 African elephants.

As raised above, the importance of having duly qualified personnel to guarantee the success of these types of logistical maneuvers. Before leading any ultra-heavy lifting or transport operation, these operators receive very specific training to ensure strict compliance with key safety regulations. For operators who will be using SPMTs in their work, it is necessary to certify their preparation beforehand so they can evaluate, on site, issues such as load stability and Last Minute Risk Assessments (LMRA) to be prepared for any contingency. Likewise, it is essential that these operators are duly qualified in reading and interpreting transport plans and in the configuration of the devices they will use and their power units. All this is done to ensure that during the transport of thousands of tons of loads, no problems occur that would endanger the load itself, the environment, or the human team carrying out the operation.

If the human team needs to have very high preparation, it is also essential to have the machinery that best suits the needs of each project. Ultimately, much of the project’s success depends on having the right cranes, SPMTs, or barges. In this sense, there are not many companies in the world capable of precisely advising their clients on what machinery they truly need, and deploying it from anywhere in the world to ensure the success of the project and strict adherence to all deadlines. Sarens is one of them, with a crane fleet of more than 1600 units distributed worldwide, ensuring that when a specific unit is needed, it can be made available as quickly as possible. The high specialisation of the cranes, with some in the range of giant cranes – in Sarens’ case, the latest crane to join this family, the SGC-170, is capable of lifting 3200 t using only electricity as a power source – helps ensure that there are no delays in heavy lifting maneuvers, the assembly of these loads at manufacturing plants, or the preparation of loads for transport to their final locations.

New alternatives in search of a cleaner energy sector

In the preceding paragraphs, we focused our attention on gas as a tool for transition towards an increasingly clean and environmentally friendly energy sector. Although it is not the only one the industry has focused on in recent years. Alternatives such as biomethane and biogas, which can be produced from organic waste and injected directly into the existing gas network, or the commitment to hydrogen, which currently involves planning and adapting the existing gas pipeline network to make it compatible

for transporting this renewable gas – either blended with natural gas or, in the near future, in its pure form – are some of the necessary steps to contribute to the gradual decarbonisation of the industry.

Over the past few years, efforts have been redoubled to capture the polluting gases produced in the hydrogen refining process. A clear example of this is the Polaris CCS project, the construction of which has already begun in Alberta, Canada. This project will have a clear environmental impact when it starts operating in 2028, as it will be capable of capturing more than 650 000 tpy of CO2 from the Shell Energy and Chemical Park in Scotford, near Edmonton. In other words, this project will be able to capture and store approximately 40% of all CO2 from the refining complex and about a quarter of the emissions from the chemical plant.

As we see, the industry’s drive to find new ways to ensure a sufficient supply of increasingly clean energy is ceaseless. Beyond the simple effort to guarantee sustainable production, the work of companies like Sarens to ensure that all logistical and transport maneuvers are carried out correctly and safely contributes to keeping this industry moving forward. Therefore, we will continue working hand-in-hand with public and private institutions to guarantee the success of the projects launched in the coming years, ensuring the work of highly qualified operators and the use of appropriate machinery for each project. Only in this way can we secure the energy transition that Europe needs.

Figure 4. Sarens’ SGC-170 and SGC-120 cranes in the Port of Rotterdam.

Figure 5. One of the units of the Shell’s Polaris Carbon Capture project near Edmonton (Canada) during its transport using two Kamag K25 platform trailers.

Peter Westerkamp, Vice President of Automation – Global Sales, LUFKIN Industries, highlights why the industry must adopt new, physics-based algorithms designed specifically for modern well trajectories.

ver the past 15 years, drilling has undergone a dramatic shift from predominantly vertical to largely deviated and horizontal trajectories. Advances in drilling technology and the shale revolution have made horizontal wells the norm in many fields, with roughly 86% of new wells today deviated or horizontal.1

Unconventional drilling completely changed the landscape of artificial lift, forcing operators to learn the nuances of producing from deviated well bores with long laterals instead of from simple vertical wells.2 Horizontal and highly deviated wells experience unique downhole conditions, the vertical sections often are tortuous rather than straight vertical – the rod string often lies against the tubing, creating extra friction.

These factors affect how artificial lift systems like beam pumps (rod pumps) must be run. However, much of the industry’s rod pump optimisation technology was developed decades ago for vertical wells and has not fully kept pace with modern well profiles.

Legacy rod lift algorithms: built for vertical wells

The legacy rod lift optimisation algorithms in wide use today trace their lineage back 40 - 60 years. Rod pump controllers traditionally rely on wave-equation modeling of the sucker rod string motion – a mathematical approach dating to the 1960s (refined in the early 1990s) to accurately simulate vertical well behaviour.3 These models served the industry well when wells were mostly vertical and straight, as they

could predict downhole pump loads and fluid levels for pump-off control in a simple environment.

The traditional models assume an ideal, vertical wellbore, neglecting Coulomb (mechanical) friction forces that are insignificant in a straight hole but have a significant impact in deviated wells. In deviated wells, rods bend through curves and continually rub on the tubing, introducing drag friction and side loads that the older verticalwell algorithms were not designed to handle.4

The effects of well inclination on fluid columns and pressure distribution are also different. Consequently, applying yesterday’s vertical-well software to today’s complex deviated wells often yields inaccurate or misleading results. Mathematical equations, originally designed for vertical wells, do not account for deviation and will be inaccurate calculating pump efficiency when used on deviated wells. The legacy math and assumptions are out of tune with the physical reality in deviated wells.

Why purpose-built deviated-well algorithms are critical

Given the operational pain points, it’s evident that rod pump automation needs a fundamental upgrade. Modern deviated wells demand purpose-built algorithms that recognise the true physics of inclined wellbores. The good news is that such algorithms are now emerging, and they directly tackle the problems legacy models ignore.1

A new updated wave equation, validated with downhole dynamometer tools, incorporates real-world forces that vertical models did not take into account. By accounting for the well’s trajectory and inclination and including the effects of rod-on-tubing friction and variable gravitational forces along a deviated path, this new wave equation provides a far more precise representation of downhole conditions. In essence, the software no longer assumes an ‘ideal’ vertical motion – it computes what is actually happening in a curved well to deliver true visibility into subsurface pumping conditions.

Key pump parameters that were once a guessing game can now be determined with accuracy. For example, the controller can correctly calculate pump fillage on each stroke, even in a severely deviated section, as well as the effective stroke length because the model knows how friction and inclination are affecting the pump’s action. With an accurate picture of downhole dynamics, the rod pump controller can much better optimise a well in real time and more accurately predict daily production. The system can adjust the pumping speed based on accurate pump fillage and load data, avoiding either over or under pumping a well. Providing a more efficient production process and a longer lasting downhole installed pumping system.

A more accurate representation of the pump card, a graphical presentation of downhole pump conditions, provides improved diagnostic accuracy. In short, modern algorithms enable adaptive control strategies that simply were not possible (or reliable) before.5

Another benefit of the improved mathematical model in software is the ability to design and operate a pumping system that is more resistant to failure. By accurately predicting the additional friction forces and side loads on rods in a deviated well, the software can recommend appropriate hardware placement to mitigate wear and tear.

During operations, advanced automation software actively monitors for signs of downhole issues that older systems would miss. It can detect abnormal pumping conditions early on, making it possible for operators to investigate and address issues before they lead to a failure. Essentially, the new algorithms serve as a preventative maintenance aid, identifying true failure risks in real time.

The overall effect of these improvements is a significant boost in reliability, efficiency, and reducing overall production costs. With

the rod lift system working consistently within its proper operating envelope, rod and pump wear is dramatically reduced. Substantially longer run times between failures can be achieved by upgrading to deviated-well-specific control.

By keeping the rods out of constant contact with the tubing (via improved rod design and rod guide placement), rod string and pump life are extended, enabling to the industry goal of continuously increasing operation between work overs. Eliminating even a single workover intervention during the life of a well can save tens of thousands of dollars in direct costs – not to mention avoiding the production revenue that would be lost during downtime.5 Many operators have hundreds, if not thousands, of rod pumped wells, these savings scale up significantly with widespread implementation.

Aligning lift technology with modern wells

The transition from legacy vertical-well mathematics to validated horizontal-well algorithms represents more than just a software update. It fundamentally alters how the industry approaches artificial lift optimisation by aligning pumping technology with the realities of the deviated wells being drilled.3

Companies that embrace these advanced, deviated-well-specific algorithms are positioning themselves to maximise uptime and output while minimising risk in the most challenging well environments. In an industry focused on squeezing maximum value from every well, the message is clear: the ‘brains’ controlling our rod lift systems must evolve to match modern well designs. Fortunately, the technology to do so exists now and has been validated in the field, and is delivering measurable improvements in production performance and operating costs.1

For oilfield operations, this evolution means a new era of reliable, efficient rod lift production. By replacing 40 year old vertical-well algorithms with next-generation deviated-well intelligence, oilfield companies can significantly enhance production and equipment longevity. In practical terms, that equates to lower workover costs, lower power bills, longer-lasting pumping systems, and more barrels on the books.

About the author

Peter Westerkamp is Vice President of Automation – Global Sales at LUFKIN Industries. With a global career spanning engineering, sales, and product innovation, he has led numerous R&D initiatives and is a frequent speaker and contributor to organisations such as SPE and ALRDC.

References

1. LUFKIN Industries. (n.d.). NOVAWAVE. https://www. lufkin.com/solutions-services/automation/novawave/

2. WISEMAN, P. (n.d.). Onward and upward: Artificial lift in the 21st century. Permian Basin Oil & Gas Magazine. https://pboilandgasmagazine.com/onward-andupward/

3. WESTERKAMP, P. (2025, June). Artificial lift: Modern rod-lift automation algorithms for deviated wells. World Oil. https://read.nxtbook.com/gulf_energy_ information/world_oil/june_2025/artificial_lift_ westerkamp_lufkin.html

4. Artificial Lift Research and Development Council. (n.d.). Horizontal Well Downhole Dynamometer Data Acquisition Project (HWDDDA). https://alrdc.com/hor izontalwelldownholedynamometerdataacquisitionp roject-hwddda/

5. LUFKIN Industries. (2025, April 23). LUFKIN introduces Well Manager™ 2.0 with NOVAWAVE™ [Press release]. Globe Newswire. https://www.globenewswire.com/ news-release/2025/04/23/3066416/0/en/LUFKINIntroduces-Well-Manager-2-0-with-NOVAWAVE.html

Figure 1. NOVAWAVE old vs new pump card.

Standout solutions

Michael Coburn, Director of Engineering and Project Management, Blackmer (PSG Grand Rapids), USA, analyses the challenges of pumping liquids in the oil and gas industry, and explains why magnetically driven sliding vane pumps are emerging as a superior solution.

he oil and gas industry continues to be the backbone of the global energy supply chain, powering economies and fuelling innovation. This sector accounts for nearly 80% of the world’s energy use, according to the Energy Institute. Countries like India (89.2%), Russia (87.5%), China (81.5%), and the US (80.5%) are leading consumers of these traditional energy sources.

Pumps play a pivotal role in this industry, ensuring the smooth transport of natural gas, oil, and other liquids across various stages of production. Oil and gas applications, however, provide multiple challenges for pumps. The

products that pass through these pumps range from natural gas and petroleum, to crude oil and even biofuels.

These raw materials present pumps with a multitude of difficulties, such as the range of viscosities between crude oil and natural gas vapours for example. Some oil and gas liquids contain solids and particulates, creating additional processing challenges. Other times, there is not sufficient product passing through the pump, creating a dry run environment that can cause catastrophic damage over time. Another challenge is keeping the valuable oil and gas liquids contained within the pump. Some pump technologies, especially those not well suited for a wider viscosity range,

Figure 1. Oil and gas applications require pump technologies that are leak-free, dry-run capable, can handle solids, can operate off the BEP and can run without any cavitation-causing NPSH imbalances occurring. Sliding vane magnetic drive pumps can address all those challenges.

2. The operating principle of sliding vane pumps ensures volumetric consistency through a number of self-adjusting vanes that slide in and out of the pump rotor, creating chambers that carry the same amount of fluid to the discharge port.

are prone to leaks. This may lead to potential safety risks, negative impacts on the environment, and ultimately a loss of product.

That’s why oil and gas operators should select a pump that can address the common pain points found in this sector. Some styles of pump are better suited to applications in the oil and gas industry, compared to others. This article dives into the game-changing role of magnetically driven sliding vane pumps (mag drive), exploring their unique capabilities and how they excel in even the most demanding environments.

Common pump choices

There is no shortage of pump options for operators in the oil and gas industry. The range of applicable pumps means operators must consider the benefits and drawbacks of each pump before making their final decision.

The most common pump found in oil and gas operation is the centrifugal pump. These pumps use impellers with a radial outlet to transfer rotational mechanical energy to the liquid by increasing its kinetic energy, which is then used to transport the liquid to the discharge port. Centrifugal pumps excel at transferring low-viscosity fluids at high flow rates.

Despite their popularity, centrifugal pumps can struggle in oil and gas applications. While some models may offer a sealless and leak-free option, they struggle with solids, abrasive media, and vapour mixtures. They also are not equipped for dry run operation and lose efficiency when pumping conditions change.

Centrifugal pumps operate most effectively at their best efficiency point (BEP), but their operating performance suffers when they deviate. This is especially true when centrifugal pumps fall out of their BEP when dealing with fluctuations in viscosity, pressure, and flow rate.

Gear pumps are another common choice for oil and gas operations. This technology uses meshing gears to move liquids. Liquid enters the suction port within the teeth between a rotor gear and idler gear, creating an atmospheric vacuum that pulls the liquid into and through the pump. Two variations of this pump – internal and external – effectively process high-viscosity liquids.

Similar to centrifugal pumps, some gear pump models may provide sealless, leak-free operation, but they are not well suited for dry run operation or vapour mixtures. The wear parts on this pump also affect their longevity and effectiveness over time. The gears in gear pumps wear down over time, impacting flow rate performance.

The standout pump for oil and gas

Cavitation and vapour mixtures

Leak-free pumping

Seal-less technology

Self-priming operation

Product recovery

Magnetically driven sliding vane pumps stand above other pump technologies used in the oil and gas industry.

Sliding vane pumps feature self-adjusting vanes that ensure the pump functions at its optimal efficiency throughout its lifetime. These pumps use a rotor with sliding vanes that draw the liquid in behind each vane, through the inlet port and into the pumping chamber. As the rotor turns, the liquid is transferred between the vanes to the outlet

Table 1. Chemical transfer capabilities comparison for sliding vane, centrifugal, and gear pumps

Figure

where it is discharged as the pumping chamber is squeezed down. Each vane provides a positive mechanical push to the liquid before it.

Mag drive sliding vane pumps do not suffer from these setbacks. This technology does not contain dynamic seals, providing a leak-free pumping solution capable of handling pumping conditions that feature varying system pressure, near zero NPSHa, liquid/vapour mix and suspended solids.

The composition of some mag drive vane pumps allows them to provide indefinite dry-run capability. To achieve this benefit, operators should consider a variation that includes a non-magnetic containment shell, a non-cantilevered rotor design, self-lubricating vanes and sleeve bearings, optimised porting and clearances, and a lower running speed to create less frictional heat during a dry run event. When these operational features are in place, this type of sliding vane pump can run dry continuously with minimal risk of damage or failure.

While there is some skepticism about a pump’s ability to run dry for longer stretches, mag drive sliding vane pumps with composite containment shells don’t suffer the same drawbacks as competitive technologies. Those pumps that falter from longer dry run cycles tend to have bushings made from sensitive ceramics, temporary coatings or soft composites, all of which will suffer under extended dry run times.

Mag drive sliding vane pumps can also handle contaminants, with the ability to process liquids with suspended-solids levels of up to 20%. These pumps also function as a near zero-NPSHr solution, making them ideal for challenging pump inlet conditions. They can sustain optimal performance standards with liquids containing up to 20% vapour or air.

Viscosity fluctuations also do not impact these pumps the way they do with competing technologies. When mag drive sliding vane pumps include the characteristics that allow for

extended dry run times, they can also handle a wide viscosity range from 1 cP to 4250 cP, which is ideal for oil and gas applications.

Unlike competitive technologies, such as centrifugal pumps, their performance will not degrade in the liquid’s viscosity drops below 1 cP or rises above 1 cP. Other technologies can handle varying viscosities, but not as wide of a range, which the oil and gas industry encounters. That’s why sliding vane magnetic drive pumps excel in oil and gas applications. They are viscosity flexible.

Conclusion

Pumps will always play a pivotal role in the oil and gas industry when transporting raw materials from the wellhead to the city gate. Because of their importance, operators must select a pump that meets all their processing and transporting needs. While the options are plentiful, sliding vane magnetic drive pumps provide an array of performance benefits without the common pitfalls of competing technologies.

Figure 3. Sliding vane pumps do not contain dynamic seals, providing a leak-free pumping solution capable of handling pumping conditions that feature varying system pressure, nearzero NPSHa, liquid/vapour mix and suspended solids.