Q1) How can digital technologies improve overall pipeline safety without increasing operational complexity?
Tim: Digital technologies fundamentally transform pipeline operations by replacing fragmented, reactive approaches with integrated, predictive systems. The key lies in creating unified digital ecosystems that consolidate multiple safety functions into streamlined workflows.
Traditional pipeline operations often involve disparate systems for SCADA, integrity management, leak detection, and compliance tracking. Modern digital platforms integrate these functions into single interfaces, eliminating the complexity of managing multiple software systems and data silos while providing comprehensive visibility. For example, Pipeline Integrity Management Systems (PIMS), such as Synergi Pipeline, can help optimise inspection intervals, focusing resources on high-risk areas while potentially extending intervals for low-risk areas through automated defect matching and corrosion growth assessment. This intelligent prioritisation reduces the burden on operators while enhancing safety outcomes.
Beyond integration, digital twin technology creates virtual pipeline replicas that enable automated anomaly detection, providing contextual alerts and regulatory-compliant response suggestions. Solutions like Synergi Pipeline flag issues for human review and suggest mitigation responses based on relevant regulations and operating conditions, presenting clear recommendations rather than overwhelming operators with raw data.
The transformation is from reactive to proactive management. Machine learning models continually improve their accuracy as they process more data, integrating information from inline inspection (ILI), external corrosion assessments, and cathodic protection surveys. Rather than overwhelming operators with data streams, these systems can present unified, actionable insights that enhance safety while simplifying decision-making.
Q2) What role do evolving standards and regulations play in shaping future pipeline safety strategies?
Tim: Recent updates to integrity management requirements, including the 2022 Gas Transmission Final Rule in the US, are driving operators toward more sophisticated, risk-based approaches. Some UK and European regulatory frameworks have similarly allowed risk-based approaches for several years, provided they are supported by sufficient, accurate data and robust analytical frameworks.
Modern regulations emphasise performance-based integrity management, requiring equivalent understanding of pipeline condition regardless of the specific technology used. This technology-neutral approach encourages innovation while maintaining safety standards – operators can use ILI, direct assessment, or other technologies that provide comparable insights.
The regulatory shift toward continuous program evaluation and improvement creates a framework that actively encourages technological advancement. This evolution requires Pipeline Integrity Management Systems (PIMS) – encompassing both software platforms and operational procedures – to be inherently flexible and adaptable to varying regulatory requirements across different jurisdictions. Rather than prescribing specific technologies, evolving standards focus on outcomes and risk reduction, allowing operators to adopt emerging technologies that can demonstrate equivalent or superior safety performance.
The Pipeline Integrity Management market growth reflects this shift toward rigorous regulatory standards and risk-based inspection strategies, with operators increasingly seeking adaptable solutions that can demonstrate compliance across diverse regulatory frameworks.
Q3) What are effective ways to improve the safety and integrity of pipelines that are difficult to inspect with conventional methods?
Tim: When conventional ILI is not feasible due to construction constraints like diameter changes, sharp bends, or operational limits, including pressure and flow restrictions, targeted alternative assessment methods become crucial.
Enhanced direct assessment methodologies have evolved significantly, particularly for internal corrosion assessment. These require sophisticated feasibility analysis and region-specific criteria development, with analysis covering entire pipeline systems while applying remediation criteria to specific segments.
Distributed sensing technologies show particular promise. Fibre optic distributed acoustic sensing provides continuous monitoring along entire pipeline lengths, detecting anomalies that periodic inspections might miss. Risk-based integrity management prioritises assessment scheduling based on comprehensive factors – previous results, materials, environmental conditions, and operational history – ensuring resources focus where they are most needed.
Q4) How can leak detection strategies be adapted for new transport media like hydrogen or CO₂?
Tim: Hydrogen and CO₂ require fundamentally different detection approaches due to their unique physical properties. Hydrogen’s smaller molecular size and rapid dispersion characteristics demand enhanced sensitivity and faster response times compared to traditional natural gas systems. CO₂ presents different challenges, particularly in supercritical states where density changes can affect conventional detection methods. Supercritical CO₂ transport requires pressure and temperature monitoring systems that can detect phase changes, indicating potential leaks.
Existing leak detection systems serve as foundations for energy transition applications, as demonstrated in power-to-gas hydrogen production and supercritical CO₂ applications. However, the U.S. Department of Energy’s $25 million+ investment in hydrogen leak detection research indicates that significant technological gaps remain, particularly for large-scale pipeline networks, where detection sensitivity and response speed become critical safety factors.
Q5) What are the key factors to consider when evaluating the condition of pipeline coatings in aging infrastructure?
Tim: With many pipeline networks’ average age approaching or surpassing 40 years, coating assessment requires a comprehensive evaluation of adhesion, dielectric strength, and defect density. Environmental factors significantly impact coating performance – soil chemistry, moisture content, temperature cycling, and corrosive substances all accelerate degradation over time.
The critical relationship is between coating condition and cathodic protection effectiveness. Well-coated pipelines may have higher localised current densities at small, infrequent defects, while poorly coated systems show more uniform, lower current densities across larger areas.
Assessment techniques include close-interval potential surveys, DC voltage gradient surveys, and AC voltage gradient methods. Integration with historical data, including materials, manufacturing information, leak history, and cathodic protection records, enables the prediction of degradation patterns and the optimisation of maintenance strategies.
Q6) How can interference from surrounding infrastructure (e.g. AC/DC interference) affect corrosion protection, and what strategies help mitigate these risks?
Tim: AC interference from high-voltage transmission lines creates current density concentrations at coating defects, with the highest corrosion rates on holidays of 1-3 cm² surface area. The key insight is that current density, not just voltage levels, determines corrosion risk.
Standards such as NACE SP21424-2018-SG and BS EN ISO 18086 establish criteria requiring AC current density control below 100 A/m² when DC current density is less than 1 A/m². These standards recognise the interrelated nature of AC and DC current density effects on corrosion rates.
Mitigation strategies can focus on grounding systems using sacrificial anodes, AC and DC decouplers or anode ribbons in specialised backfill. Comprehensive monitoring protocols require measuring AC pipe-to-soil potentials whenever pipelines are in AC power corridors, with particular attention during peak power demand periods when interference is highest. The installation of permanent coupons will also greatly help with obtaining the required AC data.
Recent research conducted by DNV has also identified that areas most susceptible to AC interference can be at locations where the pipeline and AC overhead lines diverge after they have been parallel. GIS spatial analysis algorithms can automate the identification of these locations, giving operators the knowledge of where to target current density readings and install mitigation.
Q7) How can digital tools improve the long-term resilience of pipelines exposed to geohazards?
Tim: Digital twin technology integrated with geohazard modelling enables predictive analytics and scenario planning that transform reactive maintenance into proactive risk management. These systems create dynamic, real-time views of pipeline integrity by integrating material data, terrain data, and deriving soil depth from LiDAR with high-resolution inspection results.
Geohazard modelling can simulate the impacts on pipeline systems due to landslides, earthquakes, flooding, and erosion. GIS spatial analysis within PIMS combines digital twin XYZ data for pipeline location and DTM (digital terrain models) to derive high-risk locations from previously siloed datasets. When combined with real-time weather and climate data integration, this can create early warning capabilities that trigger protective measures before damage occurs.
In the near future, the power lies in continuous learning systems that integrate historical data with real-time monitoring and predictive modelling. These systems become more effective over time, improving their ability to predict and respond to evolving environmental conditions throughout the pipeline’s operational life, ultimately creating infrastructure that adapts to changing risk profiles.
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The Experts
Tim Manns, Principal Consultant, Digital Solutions, DNV
Tim joined DNV in 2006 and is currently a technical lead for integrity and GIS implementation projects for the UK and European pipeline integrity management market, primarily using Synergi Pipeline. Before this role, Tim held the position of Head of Section, responsible for the European teams implementing pipeline and plant integrity software products.
