The assessment of dielectric stability in transformer oil is a critical aspect of condition monitoring in high-voltage equipment. Partial discharges (PDs) are widely recognized as early indicators of insulation degradation, including the progressive degradation of insulating oil; however, their behavior under stable dielectric conditions remains insufficiently characterized in controlled experimental environments.

This work presents an experimental approach to evaluate dielectric stability through the analysis of partial discharge energy signatures derived from electrical measurements. A modular test cell was developed to reproduce controlled PD conditions using spherical electrodes with adjustable inter-electrode distances. This configuration allows the generation of repeatable discharge events under well-controlled electrical conditions representative of early-stage insulation stress. Repeated experiments were conducted under controlled experimental configurations, and current signals were recorded during each discharge event using synchronized measurement equipment. The analysis focuses on physically interpretable indicators, including peak current amplitude and energy-based descriptors computed from the electrical signals.

The results show that, under stable dielectric conditions, these indicators exhibit low dispersion and no significant drift across repeated measurements, indicating stable dielectric behavior and consistent discharge mechanisms.

These findings demonstrate that PD energy signatures can serve as reliable and practical indicators for monitoring dielectric stability and detecting early signs of insulation degradation in transformer oil. The proposed approach provides a relevant basis for condition monitoring strategies in high-voltage insulation systems and is particularly suited for early-stage diagnostics.

As a common surface defect in pipeline steel, surface scratches significantly affect hydrogen embrittlement sensitivity due to their roughness characteristics. It is generally recognized that rougher surface scratches tend to result in higher susceptibility to hydrogen embrittlement. However, in this study, the influence of surface scratch roughness on hydrogen embrittlement sensitivity was systematically investigated in X80 pipeline steel using slow strain rate tensile testing and hydrogen microprint techniques, leading to the discovery of an unexpected phenomenon. Specifically, as the scratch features transitioned from coarse to fine, the hydrogen embrittlement sensitivity first decreased and then increased—a non-monotonic trend that has not been previously reported in the literature. This behavior originates from the synergistic effect between the surface scratch morphology and the residual compressive stress induced by the scratching process, with the two factors exhibiting a competitive relationship. As the grit size of the abrasive paper decreases (i.e., the finer the grit, the smaller the scratch roughness), the scratch dimensions decrease, which helps reduce hydrogen embrittlement sensitivity. At the same time, however, the surface residual compressive stress also diminishes, thereby increasing hydrogen embrittlement sensitivity. The competition between these two effects results in the observed non-monotonic variation in hydrogen embrittlement sensitivity with increasing abrasive paper grit size. Hydrogen-induced cracks almost invariably initiate at the scratch grooves, likely due to localized hydrogen enrichment driven by stress concentration during tensile loading—a mechanism strongly supported by finite element simulation results.

Non-metallic materials such as polyethylene pipelines and glass fiber-reinforced epoxy composites are widely used in energy infrastructure due to their corrosion resistance, mechanical properties, and cost-effectiveness. However, premature failures in buried and externally exposed components are often attributed to thermal or oxidative aging, while biological deterioration remains largely overlooked. Although bacteria are well known to cause microbiologically influenced corrosion (MIC) in metallic systems, the analogous process in non-metallic materials, referred to as microbiologically influenced degradation (MID), particularly driven by filamentous fungi, has received limited attention. This study aimed to characterize the degradation mechanisms associated with fungal colonization of polymeric and composite materials used in energy distribution systems. Failure analyses were conducted on polyethylene and glass fiber-reinforced epoxy pipelines exhibiting external surface deterioration under field conditions, integrating documented case studies provided by the Corporación para la Investigación de la Corrosión (CIC, Colombia). The methodology included visual inspection, Fourier transform infrared spectroscopy (FTIR), scanning electron microscopy (SEM), thermogravimetric analysis (TGA), differential scanning calorimetry (DSC), and mechanical testing (tensile strength and hardness), along with physicochemical analysis of soils in contact with the pipelines. Fungal isolation from pipe surfaces and adjacent soils was performed to confirm active colonization. SEM analysis revealed surface alterations such as erosion, damage, and wear. FTIR results showed oxidative degradation with the appearance of –OH and C=O functional groups. Mechanical testing indicated variations in tensile strength and hardness, while TGA and DSC analyses showed changes in degradation behavior and the presence of secondary compounds not associated with the original material. Soil conditions favored microbial growth, supporting fungal utilization of polymeric materials as a carbon source. These findings demonstrate that fungal-driven MID can significantly affect the durability of non-metallic infrastructure components and should be incorporated into integrity management and risk assessment strategies.

Introduction:
Corrosion behavior of structural steels in extreme environments remains insufficiently understood, particularly in Antarctic conditions where low temperatures, variable salinity, and high oxygen solubility may significantly influence degradation mechanisms. This study investigates the in situ corrosion performance of ASTM A36 steel in Antarctic marine and glacier waters to provide insight into material durability in polar environments.

Methods:
Electrochemical characterization was conducted using techniques such as open-circuit potential, linear-sweep voltammetry, and electrochemical impedance spectroscopy in both Antarctic seawater and glacier water. Complementary gravimetric analysis was performed using weight-loss measurements during controlled exposure periods. Surface and microstructural characterization of the corroded samples was carried out using scanning electron microscopy after the specimens were transported from Antarctica to the laboratory.

Results:
Electrochemical results revealed distinct corrosion behaviors between the two environments, with active corrosion activity observed in marine water, attributed to increased ionic conductivity and chloride content. Glacier water exhibited important electrochemical activity, and general corrosion attack was detected. Gravimetric measurements were consistent with electrochemical findings, confirming mass loss in glacier and marine waters. SEM analysis revealed the formation of heterogeneous corrosion products and localized degradation features, which correlate with the electrochemical data.

Conclusions:
The combined electrochemical and gravimetric approach demonstrates that Antarctic environmental conditions significantly affect corrosion mechanisms of ASTM A36 steel. Marine exposure accelerates corrosion due to salinity, while glacier water promotes measurable degradation and the formation of corrosion products across the surfaces. These findings contribute to understanding material performance in polar regions and support the design of more durable infrastructure for extreme environments.

Hydrogen embrittlement (HE) is a critical bottleneck that limits the safe transport of hydrogen through existing steel pipelines and hinders the widespread use of hydrogen as a clean energy carrier. This work demonstrates that laser polishing (LP) can significantly improve the HE resistance of X80 pipeline steel in a high-pressure H₂ environment, primarily by constructing a subsurface microstructural barrier rather than merely smoothing the surface. By systematically adjusting the laser power (6–20 W) and the number of processing passes, an optimal heat input window (10 W) was identified, wherein the microstructure of the modified layer was optimized. This resulted in a gradient transition layer consisting of ultrafine nanograins near the surface, lath-shaped nanograins, and an underlying heat-affected zone (HAZ), along with a synergistic increase in dislocation density and interface/trap density. The more uniform grain-size transition caused by multiple passes effectively reduced the risk of interfacial hydrogen embrittlement due to the mismatch in physical properties between the modified layer and substrate. This artificially constructed subsurface barrier effectively reduces hydrogen diffusion and permeation, as indicated by the lowest apparent diffusion coefficient (D_app) observed at 10 W, which further decreases with multiple passes. Slow-strain-rate tensile tests conducted in high-pressure H₂ showed a significant reduction in elongation loss (I_δ) and an increase in absorbed energy, both closely linked to microstructural changes. Fractographic analysis revealed a shift in fracture mode toward a more ductile behavior, with enhanced local plasticity, consistent with the HELP mechanism. Notably, the best HE resistance was achieved even with the highest surface roughness, indicating that HE mitigation depends more on subsurface barrier integrity than surface topography alone. This work offers mechanistic understanding and a practical surface-engineering approach for developing hydrogen-resistant pipeline steels, with direct benefits for safely and economically converting existing infrastructure for hydrogen transport.

This research unveils a case study on the structural integrity management of an ageing Floating Production Storage and Offloading (FPSO) unit and Single-Point Mooring (SPM) calm buoy, with a primary focus on the degradation effects of corrosion. Historically, as FPSO and SPM calm buoys exceed their initial design life, the threat of corrosion wastage poses a significant threat to structural reliability, particularly in critical areas such as the hull and deck plates. This paper presents a comprehensive assessment methodology involving in-service survey data, corrosion wastage computations, and structural reassessment to evaluate the remaining thickness of these components, which is a measure of their remaining strength. In conclusion, for the FPSO hull, since 20.12 mm is greater than 19.75 mm, it will serve for the intended 15 years. Thus, the hull is adequate for an additional 15 years in service. Similarly, for the SPM calm buoy hull, since 11.73 mm is greater than 9.725 mm, it will also serve for the intended 15-year extension. Thus, the hull is adequate for the 15-year life extension. Therefore, in each case, the t-end of design life is greater than the t-minimum for life extension. Hence, no steel plate renewal is required on the hulls for the FPSO and SPM calm buoy. These computations were made possible by a computer program code-named HULL LIFE written in the C++ programming language. On the other hand, the computations carried out on the deck plates allowed the recommendation of various mitigation strategies to remedy the corroded deck plate strakes that had fallen below the limiting values. Other strakes or zones that fell within the regime of substantial corrosion were recommended for close monitoring.

Floating production, storage and offloading (FPSO) and single-point mooring (SPM) calm buoy mooring chains represent the single point of failure for most offshore floating terminals. However, the recent rise in mooring line failures on FPSO and SPM units, particularly in West Africa, has underscored a critical industry blind spot: the underestimation of corrosion effects in remaining useful life calculations (RUL). Traditionally, remaining strength models assume pristine geometric conditions or apply a uniform corrosion allowance. However, in-service inspections of SPM and FPSO chains frequently reveal accelerated wastage in the splash zone, none of which is adequately captured by linear degradation models. This paper addresses this gap by developing a dedicated RUL estimation methodology centred on corrosion-driven deterioration. We analyzed in situ data from 76 chain samples to characterize corrosion rate distributions specific to the R3 mooring chain grade. The resulting model demonstrates how localized corrosion reduces the net cross-sectional area of the mooring chains' links. By moving from a time-based replacement philosophy to a corrosion-informed RUL prognosis, this work provides operators with the tools to optimize data interpretations, plan for chain replacements and avoid being faced with multiple line failures or domino effects and ultimately system failure while in operation. Over approximately 20 years of service, an operator replaces the top chains of its FPSO mooring chains twice, despite being originally selected for a 20-year service life. This occurs after the first 10 years and, secondly, after the second 10 years due to the excessive corrosion wastage on the FPSO and SPM mooring chains in West Africa. These decisions were reached through detailed mooring chains surveys, measurements and assessments using class society equations. The quantitative results showed that the reductions in the mooring chains' minimum breaking strength (MBS) fall within the range of 10-20%.

Stress corrosion cracking (SCC) remains one of the most critical degradation mechanisms affecting the structural integrity of North American natural gas pipeline infrastructure. SCC-driven failures threaten the reliability of energy transportation systems and can result in severe safety, environmental, and economic consequences. Despite extensive integrity management programs, SCC continues to challenge conventional monitoring and mitigation strategies because it arises from complex interactions among materials, stresses, and service environments. This study examines SCC from a metallurgical perspective, linking materials science fundamentals with pipeline manufacturing practices and operational conditions to better understand why SCC persists as a dominant failure mechanism. This work synthesizes metallurgical insights with case-based analysis of major pipeline rupture and fire incidents reported in Canada between 2005 and 2024, particularly involving high-pressure, large-diameter transmission pipelines. Published failure investigations, metallurgical examinations, and operational records were reviewed to identify recurring contributors to SCC initiation and propagation. The analysis integrates materials-related factors—including steel grade, microstructure, banding, centerline segregation, non-metallic inclusions, welding-induced residual stresses, and coating–steel interactions—with operational variables such as pressure cycling, thermal fluctuations, cathodic protection imbalance, coating disbondment, soil chemistry, and moisture ingress. The results indicate that SCC develops through the synergistic interaction of tensile stresses, SCC-susceptible microstructures, and aggressive service environments. Metallurgical evidence shows that crack initiation commonly occurs at microstructural heterogeneities and inclusion sites, while operational stresses and environmental exposure accelerate crack coalescence and unstable propagation. Case comparisons further demonstrate that manufacturing quality, coating performance, and cathodic protection management significantly influence crack growth behavior and remaining pipeline life. Overall, SCC should be understood as a system-level degradation mechanism governed by coupled metallurgical, manufacturing, and operational factors rather than a standalone corrosion phenomenon. These findings emphasize the need for microstructure-informed materials selection, improved manufacturing quality control, and predictive integrity management strategies to enhance pipeline reliability and infrastructure resilience.

Introduction

Combined marine and industrial conditions form a complex climate that complicates corrosion prediction in energy infrastructure design. The impact of pollutant mix, driven by wind action and high humidity, may affect the evolution of corrosion product formation. This study provides valuable insights into the corrosivity of a unique marine-industrial location on the tropical island of Mauritius.

Methods

S235-grade carbon steel plates are subjected to a 14-month atmospheric exposure test at a bagasse/coal thermal power plant situated 3 km from the tropical coastal sea. Weight loss analysis is performed with triplicate specimens retrieved at specific time points to determine the corrosion kinetics. Furthermore, surface analysis using SEM-EDS and FTIR helps to identify the rust phases.

Results

The results demonstrate a corrosion rate (340 gm^-2a^-1) in the medium ISO 9223 category (C3). The chloride (Cl^-) deposition rate is elevated at 74 mg m^-2 d^-1 but does not cause the formation of flaky corrosion layers. Lepidocrocite (γ-FeOOH) and goethite (α-FeOOH) are the predominant rust phases. Also, sulphur dioxide (SO₂) emissions do not lead to significant surface deposition, mainly due to the low sulphur content of bagasse and the location of the gas stack relative to the exposure rack.

Conclusion

Formation of stable corrosion products, such as (α-FeOOH), limits Cl^- penetration due to the inherently compact and dense rust layer. Extreme corrosion protection measures may not be required in bagasse/coal cogeneration plants. However, higher times of wetness and lower SO₂ emissions may lead to conditions more conducive to chloride attack in a marine region.

Introduction.
Stress corrosion cracking (SCC) is a complex degradation mechanism driven by the presence of mechanical stress, a corrosive environment, and the material’s susceptibility. Steel pipelines used for transporting natural gas and oil may be vulnerable, as SCC can initiate and propagate cracks that threaten structural integrity. In advanced stages, the progression of these cracks can reduce the load-carrying capacity of the pipe wall and, under critical conditions, may lead to failure. Consequently, the detection, characterization, and assessment of SCC-related cracking have become components of pipeline integrity management programs.

Methods.
Among the available crack detection technologies in the pipeline industry, Electromagnetic Acoustic Transducer (EMAT) in-line inspection tools have gained relevance in recent years. EMAT technology enables the detection, identification, and sizing of linear indications that may be associated with SCC. However, because of the complexity of SCC morphology (crack colonies, crack interaction), accurate classification and sizing can be challenging. Effective characterization requires field verifications that allow the operator to correlate EMAT signal responses with pipeline properties and actual conditions.

Results.
In a recent case study, field excavation results confirmed that the EMAT tool detected anomalies associated with SCC. However, subsequent destructive testing highlighted adversities in both sizing and classifying these indications, underscoring the challenges associated with characterizing SCC through an ILI alone and reinforcing the need for complementary data integration and field verifications.

Conclusion.
EMAT technology provides capability for detecting and managing anomalies associated with SCC in pipelines, but its effectiveness as part of an SCC integrity management program relies on more than the inspection tool. Threat management requires integrating EMAT results with operational, material, field excavation, destructive testing, and historical data. When EMAT ILI data is combined with material characterization and engineering assessments, operators can make informed integrity decisions and more effectively mitigate the operational risks associated with SCC.