Meet the Authors

Tom, our ICorr member, is a PhD student, who is finalising his PhD thesis at the University of Manchester with a BSc in chemistry and physics from Keele University. His research has focused on establishing multi-technique-informed

pitting corrosion detection and monitoring techniques – such as hyperspectral imaging (HSI) – for remote inspection of marine infrastructure. He has developed the use case for hydrogen mapping with laser-induced breakdown spectroscopy (LIBS) to detect occluded corrosion reactions. Additional research focuses include development of rapid, low-cost hydrogen detection routines; depassivation mechanisms; and leveraging atomic hydrogen for engineering applications.

Dirk Engelberg, our ICorr member, is a professor in materials performance and corrosion at the University of Manchester. He obtained a Dipl.-Ing. (FH) in Surface Engineering and Materials Science from Aalen University (Germany) before moving to Manchester in 2000 for an MSc in Corrosion Science and Engineering and a

PhD in Metallurgy and Materials Science. He joined the Corrosion and Protection Centre as an academic lecturer in 2010, which is now part of Metallurgy and Corrosion (Corrosion@Manchester) in the Department of Materials. Dirk’s research is centred on (i) understanding material degradation related to the storage, disposal, and decontamination of nuclear waste; (ii) applied electrochemistry and high-throughput screening techniques; (iii) development of innovative solutions for net-zero engineering; and (iv) localised corrosion, stress corrosion cracking, and hydrogen embrittlement. Dirk is also an expert in microstructure engineering and leads several cross-disciplinary projects combining mechanical, civil, and chemical engineering with chemistry, physics, and materials-based research.

Introduction

Under the Net-Zero drive, Hydrogen energy and infrastructure have seen tremendous growth with electrolyser technologies having seen a 3-4 fold increase in investment over the past years alone [1]. It is therefore expected for hydrogen to grow in its proliferation as a means for energy production and storage. However, being the smallest atom and having an extremely high diffusivity leads to deleterious effects on the mechanical properties of steels, typically referred to as hydrogen embrittlement (HE). Here, the localised presence of diffusible hydrogen atoms within the microstructure can result in local embrittlement and lead to premature component failure [2], [3], [4]. This is not limited to hydrogen storage or transport alone: hydrogen generation from cathodic sites under atmospheric corrosion conditions may also induce crack nucleation in certain alloy classes [5], [6], [7], [8], [9], [10].

It is therefore pertinent to establish techniques for localised hydrogen concentration detection and quantification in metals and engineering structures. Existing analytical methods are, however, limited. Some require the destruction of the test specimen – such as TDA/TDS [11], [12], [13] and hot/melt extraction [14], [15], [16], [17] – or adequate surface preparation – SKP [8], [18], [19] or GD-OES [20], [21]. Destructive techniques may require temporary shutdown for hydrogen contents to be measured and limits on surface condition may stymie the range of regions of interest [22], while the low diffusivity of hydrogen in widely used austenitic steels place potentially untenable detection times for devices such as gas sensors [23], [24].

Laser-induced breakdown spectroscopy (LIBS) is a localised, “quasi-nondestructive” technique for the acquisition of atomic spectra (Figure 1). A high-power laser is fired at the sample surface, often alongside a purge of inert gas (Ar, He, Ne, or other combinations [25]). A small volume (order of a few µm3) of the specimen’s surface is ablated and ionised, and optical photon emission – characteristic of the elements that make up the material – from the plasma recombination is then captured by a charge-coupled device (CCD).

Figure 1: Sketch of the Working Principle of LIBS. The Hα Line Used for Hydrogen Determination is Highlighted.

A utility of LIBS is that it is scalable, and this has been exploited for use in geological and alloy identification for in-situ inspections [26], [27]. Additionally, the LIBS technique itself can capture the hydrogen Hα line at 656.2nm [28] and has been increasingly studied in recent years, with applications ranging from tritium monitoring in fusion reactor walls to hydrogen uptake in steel welds [28], [29], [30], [31]. In this article, the use case for localised hydrogen detection and quantification is demonstrated with a portable, hand-held
LIBS device.

Experimental and Calibration

Initially, three ‘hydrogen in steel’ calibration standards of concentrations 0.95ppm (SciLab), 2.3ppm (SciLab) and 6.23ppm
(LECO) were cold mounted in an epoxy resin and cured for 48 hours before grinding to P1200 with Silicon carbide (SiC) paper to expose the steel surfaces of each. LIBS spectra were acquired using 14 locations per standard. Two LIBS shots were applied per location, with the first as a “cleaning” shot and the second shot for spectra acquisition. This was done for each location to ensure minimal contribution of hydrogenated surface contaminants.

Figure 2: Mounted Hydrogen in Steel Standards with LIBS Shot Ablation Visible on Each of the Standard Surfaces.

Subsequently, four X52 steel coupons with dimensions 50.0mm × 5.0mm × 1.2mm were cut from a pipe section with an SiC abrasive cutoff wheel before surface grinding to P1200 with SiC paper. Coupons were rinsed with DI water before washing with ethanol and drying under cold air. Each coupon was cathodically charged in 0.1M NaCl under a current density of 15 mA cm2 for 122, 165 and 203 minutes to establish different hydrogen concentration depth profiles. Coupons were rinsed after hydrogen charging with DI water and ethanol and then dried under cold air prior to LIBS acquisition. Two LIBS shots were recorded for each charging time, with spectra obtained close to the center point of the charging surface of
each coupon. The first shot was taken as surface concentration measurement with the second shot assumed to be more indicative of the immediate sub-surface hydrogen concentration, allowing influences of surface conditions to be compensated for. The time interval from specimen hydrogen charging to LIBS surface analysis was recorded and kept to a minimum—typically less than 60 seconds—to avoid excessive hydrogen effusion.

LIBS spectra were obtained with a SciAps Z300 handheld LIBS unit equipped with a Nd:YAG 1064 nm laser with energy 5-6 mJ per pulse and Ar purge. Spectral integration time and delay were 1 ms and 250 ns, respectively. All LIBS spectra were processed in the same way: Voigt peak profiles were fitted to the Hα line at 656.2 nm and Ar(I) line at 763.5 nm, respectively, for each analysis and averaged. The resultant Hα peak intensities were normalised to the Ar(I) peak intensities. This peak was chosen for normalisation (over any of the Fe peaks), as it allows for comparison between spectra taken from different materials (such as carbon steel and stainless steel) and is in principle, independent of matrix composition. In this way, hydrogen abundance is normalised to the plasma composition only.

Results and Discussion

The calibration routine with results of both LIBS shots (1st cleaning + 2nd results) is summarised in Figure 3, indicating a larger variation of the surface concentration shot. This could be due to differences in the top surface sample condition and composition, for example, due to adherent water or near-surface physical/chemical discontinuities. The plot also highlights the efficacy of using an internal standardisation routine for LIBS calibrations for hydrogen abundances in stainless steels. The relationship between measured hydrogen concentration and LIBS signal was then approximated using these standard readings and applied to spectra obtained on the cathodically hydrogen-charged X52 line pipe steel samples. Expected hydrogen concentration readings in mild steel and carbon steels are typically in the sub-ppm range (<1 ppm), up to a few ppm, considering analysis of chemical/physical surface discontinuities.

The results in Figure 4 demonstrate the expected effect of charging time under constant current on the X52 coupons. A change of the measured hydrogen concentration for X52 samples in the as- received condition (before hydrogen charging) to material cathodically charged is clearly present. However, the variation of the obtained signal is quite large and overshadows clear trends of longer hydrogen exposure times. As expected, there is a marked increase in the calculated hydrogen abundance with hydrogen exposure. Of note is that the determined ppm values from the X52 samples fall above the calibration range used and are far larger than typically expected in mild/carbon steel. It is not certain at this point how linear the relationship is between hydrogen abundance and the Hα/Ar(763.5) peak height ratio far above the tens of ppm range. In the current stage, LIBS can be used to qualitatively determine differences between charged and uncharged microstructure conditions, but more work is needed to obtain quantitively reliable hydrogen readings. Further work is currently underway to (i) isolate the effect of relative humidity (adsorbed surface water) on the obtained hydrogen signal, (ii) to deconvolute effects of multiple LIBS shots on hydrogen redistribution, and (iii) application of LIBS to measure diffusion coefficients.

Figure 3: Calibration Plot of Analysed Hydrogen Standards for Normalised Hα Peak Intensity to the Ar763.5 Peak.

Figure 4: (Left) Measured H/Ar Peak Ratios; (Right) Calculated Hydrogen Abundances.

Conclusions

A handheld LIBS device has been calibrated on hot/melt hydrogen calibration pins, and qualitative differences in hydrogen content readings have been demonstrated on cathodically charged X52 coupons from a pipe section. The adoption of LIBS as a PMI (Positive Material Identification) technique in industry is strong, with advanced applications emerging, particularly in mining, manufacturing, and quality control. This article demonstrated that with correct calibration standards and data treatment, existing routines can readily be adapted into localised hydrogen measurement techniques.
The application of these techniques for structural maintenance applications and fitness-for-service inspection is currently under development but shows great promise at this stage.

References

1. “Global Hydrogen Review 2024 – Analysis,” International Energy Agency, 2024. https://www.iea.org/reports/global-hydrogen-review-2024 (accessed 6 November 2025).

2. J P Hirth, “Effects of hydrogen on the properties of iron and steel,” Metall. Trans. A, vol. 11, no. 6, 1980, pp. 861–890. https://doi. org/10.1007/BF02654700

3. J H Chuang, L W Tsay, and C Chen, “Crack growth behaviour of heat-treated 4140 steel in air and gaseous hydrogen,” Int. J. Fatigue, vol. 20, no. 7, 1998, pp. 531–536. https://doi.org/10.1016/S0142-1123(98)00019-X

4. A Laureys, T Depover, R Petrov, and K Verbeken, “Microstructural characterization of hydrogen induced cracking in TRIP-assisted steel by EBSD,” Mater. Charact., vol. 112, 2016, pp. 169–179. https://doi. org/10.1016/j.matchar.2015.12.017

5. S J Kim, J S Park, and S-P Jung, “Corrosion-induced hydrogen evolution, absorption, and cracking behaviors of ultra-high-strength galvanized and galvannealed steel sheets,” npj Mater. Degrad., vol. 6, no. 1, 2022, p. 31. https://doi.org/10.1038/s41529-022-00245-1

6. G Z Meng, C Zhang, and Y F Cheng, “Effects of corrosion product deposit on the subsequent cathodic and anodic reactions of X-70 steel in near-neutral pH solution,” Corros. Sci., vol. 50, no. 11, 2008, pp. 3116–3122. https://doi.org/10.1016/j.corsci.2008.08.026

7. A Turnbull, “2009 W.R. Whitney Award Lecture: Local Hydrogen Generation and Its Impact on Environment-Assisted Cracking and Crevice Corrosion,” Corrosion, vol. 66, no. 5, 2010, pp. 055001-1–055001-16. https://doi.org/10.5006/1.3430461

8. D Rudomilova, T Prošek, and M Ström, “Hydrogen Entry into Steel Under Corrosion Products,” Corrosion, vol. 77, no. 4, 2021, pp. 427–432. https://doi.org/10.5006/3675

9. T L Burnett et al., “Mechanisms of Environmentally Induced Crack Initiation in Humid Air for New-Generation Al-Zn-Mg-Cu Alloys,” Corrosion, vol. 79, no. 8, 2023, pp. 831–849. https://doi. org/10.5006/4336

10. J Srivastava et al., “The influence of partially recrystallized grain structures on hydrogen-environmentally induced cracking (H-EIC) behavior of AA7085 alloy in humid air,” Corros. Sci., vol. 256, 2025, p. 113199. 

11. K Verbeken, “Analysing hydrogen in metals: bulk thermal desorption spectroscopy (TDS) methods,” in Gaseous
Hydrogen Embrittlement of Materials in Energy Technologies, Woodhead Publishing, 2012, pp. 27–55. https://doi.
org/10.1533/9780857095374.1.27

12. D Pérez Escobar, K Verbeken, L Duprez, and M Verhaege,
“Evaluation of hydrogen trapping in high strength steels by thermal desorption spectroscopy,” Mater. Sci. Eng. A, vol. 551, 2012, pp. 50–58. https://doi.org/10.1016/j.msea.2012.04.078

13. F von Zeppelin, M Haluška, and M Hirscher, “Thermal desorption spectroscopy as a quantitative tool to determine the hydrogen content in solids,” Thermochim. Acta, vol. 404, no. 1, 2003, pp. 251–258. https://doi.org/10.1016/S0040-6031(03)00183-7

14. L B Peral, A Zafra, I Fernández-Pariente, C Rodríguez, and J Belzunce, “Effect of internal hydrogen on the tensile properties
of different CrMo(V) steel grades: Influence of vanadium addition on hydrogen trapping and diffusion,” Int. J. Hydrogen Energy, vol. 45, no. 41, 2020, pp. 22054–22079. https://doi.org/10.1016/j. ijhydene.2020.05.228

15. M N Babikhina, V N Kudiiarov, A V Mostovshchikov, and A
M Lider, “Quantitative and Qualitative Analysis of Hydrogen Accumulation in Hydrogen-Storage Materials Using Hydrogen Extraction in an Inert Atmosphere,” Metals, vol. 8, no. 9, 2018, p. 672. https://doi.org/10.3390/met8090672

16. G K Padhy, V Ramasubbu, S K Albert, N Murugesan, and C Ramesh, “Hot Extraction of Diffusible Hydrogen and Its Measurement Using a Hydrogen Sensor,” Weld World, vol. 56, no. 7, 2012, pp. 18–25. https://doi.org/10.1007/BF03321361

Meet the Author

Hans has built his career on a strong practical background and a natural curiosity, leading him to a wide range of roles in materials and corrosion across operations, engineering, research, and technology. He is committed to developing and applying deep technical knowledge to deliver practical and effective solutions.

Hans is currently the global expert for Materials and Corrosion in Carbon Capture and Storage (CCS) at Shell, where he provides guidance and support to many CCS projects worldwide. To address specific corrosion challenges, he is actively involved in research collaborations with several institutes and universities. In recent years, his work has focused particularly on the effect of CO₂ purity on corrosion behaviour. Hans has published extensively on corrosion issues related to oil and gas production as well as CCS. He is also actively involved in standardisation work, including serving as Chair of SC 20 / SC 26 and a TCI for CCS at AMPP.

Introduction

To mitigate CO2 emissions from a wide range of industries, Carbon Capture and Storage (CCS) projects have been initiated to process, transport and inject CO₂ captured from multiple emitters. These CO₂ sources have a wide variety of compositions, and it has been discovered through testing in recent years that mixing the CO₂ streams can cause their impurities to react and cause precipitation of a highly corrosive acidic phase well below the water dewpoint. It was found that a group of impurities (H₂O, H₂S, SO₂, NO_x and O₂) can react to form products that include H2SO4 , HNO3 as well as elemental sulphur^1-3,, which with their low solubility4 can trigger precipitation that causes severe corrosion6,7.

Figure 1 presents a schematic overview of these so-called CCS hub projects with a wide range of industry CO2 sources.

Figure 1: Schematic Overview of a Possible CCS Hub Project that Gathers,

With the tight economics of CCS projects, it is inevitable that carbon steel will be selected for the long pipeline networks required to connect the CO₂ emitters to the storage location. This makes the management of corrosion a critical factor for the commercial viability of these projects. Corrosion control starts with setting of limits for impurities in a defined CO₂ specification. To safeguard long term integrity, control of both CO2 composition and process conditions, in combination with highly sensitive monitoring, will be required. As new energy transition technologies like CCS are developed, diligence is needed in identifying new potential corrosion threats to avoid in-service surprises.

A standard practice has been developed by AMPP (AMPP SP 21632-2025)8 that outlines the basic requirements for corrosion control for CCS projects. These include:

• Prevention of precipitation/drop-out of strong acids present due to interaction between impurities in transported CO₂ streams by validation of impurity limits for H2O, H2S, SOx, NOx, and O2.
• Continuous monitoring to control the levels below the validated conditions for liquid precipitation for all operating scenario’s,
• Assessment of the risk of potential off-spec scenario’s,
• Incorporating the worst-case for combinations of these impurities and conditions.

The generic guidance provided by AMPP SP 21632-2025 and recent literature needs to be addressed in detail during project design and operations.

Corrosion control starts with understanding the corrosion mechanisms, including the main triggers for corrosion to occur in practice. When these are identified, the worst-case compositions and conditions can be identified and tested, leading to the development and implementation of an appropriate corrosion management strategy.

This article outlines the basic principles of the corrosion mechanism associated with acid formation and precipitation and the critical factors that need to be controlled to enable effective corrosion management, and to offer guidance for tackling the challenges associated with managing newly recognised corrosion mechanisms in CCS.

Corrosion Mechanism “Reactive Phase Behaviour”

The corrosion mechanism caused by chemical reactions and precipitation in CCS is complex and uncertain. The initial reaction can form a separate phase contributing to or leading to further reactions within that phase known as “reactive phase behaviour”. In some cases (reaction) products adsorbed on metal surfaces cause corrosion before precipitation occurs.

The corrosion mechanism is visualised in Figure 2.

Figure 2: Corrosion Mechanism Caused by Mixing of Impure CO2 Streams Leading to Formation of Reaction Products that Can Adsorb or Coalesce and Precipitate as a Corrosive Phase.

 The corrosion mechanism is initiated when two impure CO2 compositions, containing H2O, H2S, SOx, NOx, and O2., interact, allowing their respective impurities to react and generate various reaction products.

The observed reactions appear to be triggered primarily by the presence of H₂S which acts as a strong reducing agent, and NO₂, which can initiate a radical chain reaction, With sufficient oxygen, these reactions can result in the formation of H₂SO₄ and HNO₃ formation 1,2,3. Chemical equilibrium calculations (CEC) can be used to determine the likely reaction products, which can be illustrated in a stability diagram that maps hydration and oxidising strengths as shown in Figure 3. Acid formation is anticipated only when sufficient oxidising and hydration strength is present,6,7,9,10

Figure 3: Visual representation of chemical reactivity as a “stability diagram” for speciation of reaction products based on the presence of different concentrations of impurities. Acids can be formed – in the orange area typically H2SO4 and in the yellow area both H2SO4 and HNO3. The blue area indicates water saturation, and the purple area covers reducing conditions where for e.g. elemental sulfur can form.

 Reaction products can coalesce to form a separate phase that can grow until the point of saturation. Due to the very low solubility of H2SO4 n CO2 precipitation can be expected⁴, even at low concentrations, however, discrepancies between precipitation by this mechanism and solubility measured by H₂SO₄ uptake have been identified7. Reasons for this include incomplete conversion of reaction products due to blocking of some chemical reactions, chemical kinetics and supersaturation before precipitation. The separate phase likely contains not only pure H₂SO₄ but also a combination of acids and water that have a strong affinity to each other potentially creating a highly corrosive phase.

Comprehensive understanding of this process is currently lacking. Once acid precipitation occurs it can settle at the bottom and cause corrosion. Continuous accumulation by replenishment significantly increases corrosion rates, while discontinuous acid formation may be less severe but is unpredictable due to uncertainty around composition of precipitants, location, and duration.6,7.

Recent findings also show that corrosion can sometimes be initiated via adsorption prior to precipitation, particularly when NOX predominates and there is an excess of H2O. This effect has been demonstrated in particular in gas phase CO2.^7,9 In these situations corrosion is likely to occur around the full circumference of the pipe and affect a larger area. The process appears to result from direct adsorption and salt formation rather than strong acid formation, which may not significantly influence this mechanism. Consequently, the corrosion rate is likely to be lower, although this has not yet been fully investigated.

Condition Driving Corrosion

Effective control of corrosion requires an understanding of the triggers and critical aspects that drive the corrosion mechanism. By managing these main triggers, it is possible to prevent corrosion and develop effective mitigation strategies. The primary factors for this corrosion process include:

• Chemistry of reaction between H₂O, H₂S, SO_x, NO_x, and O₂
  • Chemical reactions initiate mainly due to the presence of NO2 asa radical and H2S (and to a lesser extent SO2) as a strong reducing agent; radical chain reactions are initiated at low concentrations when these both are 1,2,3,6,7.
  • The presence of oxygen (O2) promotes acid formation, and excessO2 further pushes the equilibrium towards acid formation with an increase in conversion Sufficient oxidising strength is essential for acid formation and minimal levels can lead to precipitation.7,9
  • While water is required for acid formation, it is not needed for H2SO4 Even at very low concentrations, water does not appear to control this process if other hydrogen donors are available. However, too much water, even below the dewpoint, can encourage precipitation or early-stage corrosion especially when NO_x is prevalent or in gas phase.9 Therefore, strict control over water content is critical.

• Phase behaviour
  • Lower temperatures result in the lowest solubility for acids and even at low temperatures reaction kinetics are not sufficiently slowed to prevent acid formation reactions from taking
  • There is a considerable difference between the thresholds for acid formation and precipitation compared to acid solubility from uptake, likely due to chemical kinetics and coalescence. The effect of flow remains understudied, and all these uncertainties create unpredictability in this mechanism.

• Corrosion
  • High rates of continuous acid formation and precipitation can lead to severe corrosion (and possibly loss of containment) with observed rates exceeding 100 mm/year 6,7. This level of corrosion is unacceptable, so to prevent such events requires stringent control measures, real-time CO₂ composition monitoring, and alarms that immediately trigger shutdown of the source of the problem.

• Nevertheless, many uncertainties In some cases, salts may form before acids, or corrosion may precede acid formation9, typically across larger areas, with significantly lower corrosion rates. Such scenarios might be acceptable during specific upset conditions, but then a more detailed understanding is required.

Corrosion Control

To effectively manage corrosion the following actions can be taken:

1. Identifynon-corrosive CO2 compositions by determining threshold concentrations for precipitation, considering all impurities and lowest operating Chemical Equilibrium Calculation (CEC) can be used to assess reaction tendencies, oxidising/hydration strength7,9,10. and equivalent sulphuric acid concentration Cacid . These help identify worst case scenarios for acid formation and precipitation that can be tested to verify that no precipitation occurs under all operating scenario’s11.
2. Composition controls should include alarms to critical impurities at the emitter side source before acids form, as dissolved acids are hard to This requires special techniques for control since the limits can be low and stringent. Collaboration with emitters will help anticipate possible effects of upsets and enable early intervention.
3. Exceedance of individual limits may be acceptable during an upset if outside the acid formation and precipitation ranges. CEC can be used for assessment of these incidences, and acceptance may be provided H₂S and NOx are not present at the same time.
4. If an upset causes acid formation and precipitation, the impact on integrity can be evaluated based on oxidising/hydration strength and sources like H₂S and NO_x, also considering the consequence of possible delayed reactions if one impurity increases after mixing.
5. Inspection and corrosion monitoring using automated and highly sensitive probes (e.g. UT) should target low temperature areas prone to precipitation, such as a gas sphere, low-point of a vessel or pipework, considering a CRA (Corrosion resistant alloy) or cladding for such sections is For pipelines this is often too complex or costly to address fully, and it is recommended to keep conditions in dense phase with shut-in during upset scenarios and keep phase transitions to the minimum (since acid solubility seems much lower in gas phase than in dense phase).

Summary and Conclusions

Progression towards the energy transition and the development of an emerging industry, such as CCS-Hub facilities, introduces distinct corrosion challenges. Due to the rapid expansion of this sector, prompt and effective measures are essential to mitigate excessive corrosion.

To safeguard asset integrity and prevent premature failures that may adversely affect the industry’s reputation.

Effective corrosion control requires active management of the composition of the CO2 during its capture, transport and storage, especially with respect to purification and process controls. As part of a comprehensive corrosion management strategy the following steps are recommended:

1. Understand and continuously review the composition of the sources of CO₂ feeding into the project to identify a possible risk of chemical reactions that can cause acid precipitation and corrosion.
2. As carbon steel is usually the most cost-effective it is necessary to establish and enforce an IOW (Integrity Operating Window) that requires inclusion and clear definition of composition and impurity thresholds that avoid corrosive conditions.
3. Consider using CRAs in areas where a high acid precipitation risk may exist, since corrosion rates due to continuous acid precipitation can be
4. Maintain operations within the non-corrosive conditions through strict automated monitoring and control of composition.
5. Develop upset management protocols, identifying scenarios where deviations may be acceptable as long as they are not resulting in significant acid precipitation
6. Implement broader corrosion management initiatives such as:
   1. Review of compositional upsets, especially individual components to evaluate their potential impact and determine locations for inspection.
   2. Perform focussed automated inspection and corrosion monitoring at critical locations (e.g. tank bottoms or cold sections).
   3. Develop mitigation strategies, including possible closely monitored composition to prevent acid formation and precipitation, recognising that this is currently a largely unexplored topic.

Due to the numerous unknowns associated with this corrosion mechanism due to reactive phase behavior, ongoing research is being conducted to identify its key triggers. To date, only a limited range of non-corrosive composition thresholds have been established for specific conditions.

References

1. A Dugstad, M Halseid, B H Morland, “Testing of CO2 specifications with respect to corrosion and bulk phase reactions,” Energy Procedia 63 (2014) 2547-2556. https://doi.org/10.1016/j.egypro.2014.11.277.
2. B H Morland, Tjelta, T Norby and G Svenningsen, “Acid reactions in hub systems consisting of separate non-reactive CO₂ transport lines,” International Journal of Greenhouse Gas Control 87 (2019) p. 246-255. https://doi.org/10.1016/j.ijggc.2019.05.017.
3. B H Morland, A Dugstad, G Svenningsen, “Experimental based CO₂ transport specification ensuring material integrity,” International Journal of Greenhouse Gas Control, 119 (2022) https://doi. org/10.1016/j.ijggc.2022.103697.
4. B H Morland, A Tadesse, G Svenningsen, D. Springer and A. Anderko, “Nitric and Sulfuric Acid Solubility in Dense Phase CO₂,” Industrial & Engineering Chemistry Research, 2019. 58(51): p. 22924- https://pubs.acs.org/doi/10.1021/acs.iecr.9b04957.
5. J Sonke, W M Bos, S J Paterson, “Materials Challenges with CO₂ Transport and Injection for Carbon Capture and Storage,” International Journal for Greenhouse Gas Control 114 (2022): 103601. https://doi. org/10.1016/j.ijggc.2022.103601
6. J Sonke, B H Morland, G Moulie, M S Franke, Corrosion and Chemical Reactions in Impure CO₂, International Journal for Greenhouse Gas Control 113 (2024) 104075. https://doi.org/10.1016/j. ijggc.2024.104075.

7. J Sonke, Y Zheng, R I Slavchov R Walker, S M Clarke,, B H Morland, Impurity threshold definition for non-corrosive CO₂ transport – chemical equilibrium calculations and laboratory testing, International Journal of Greenhouse Gas Control,. 153 (2026) 104672. https://doi. org/10.1016/j.ijggc.2026.104672

8. AMPP SP 21632-2025 “Standard Practice for Materials Selection and Corrosion Control for Carbon Capture & Storage (CCS) Projects, 2025 https://doi.org/10.1016/j.ijggc.2026.104672 .
9. J Sonke B H Morland, G Svenningsen, Chemistry Theory and Threshold Definition for Reactions and Precipitation in Impure CO₂ Transport AMPP Conference 2026 C2026-00022 https://doi.org/10.5006/C2026-
10. R I Slavchov, M H Iqbal, S Faraji, D Madden, J Sonke, S Clarke, Corrosion maps: stability and composition diagrams for corrosion problems in CO₂ transport Corrosion Science 236, (2024) https://doi.org/10.1016/j.corsci.2024.112204.
11. J Sonke, T De Cazenove, L Galliot, J Zwart, S De Kruijf, H. Morland, Svenningsen, Corrosion Control Based CO₂ Specification, A project approach, Eurocorr 2025 ref. 54592.

Dr Vijesh Vijayan, PhD, PMP®, NACE Senior Corrosion Technologist

Dr Vijesh Vijayan is an accomplished coatings and corrosion inspection and application specialist with over 15 years of expertise in protective and marine coatings, underwater coating inspection, tank linings, thermal spray aluminium (TSA), intumescent fireproofing, and galvanising. He holds a PhD in Corrosion Engineering and multiple international certifications, including PMP®, NACE Senior

Corrosion Technologist, AMPP Protective Coating Specialist (PCS), FROSIO Level III (Red) AGA Hot-Dip Galvanising Inspector, ISO 9001:2015 QMS Lead Auditor, and Master of Yachts 200 Tons. Currently, Dr Vijesh is the Managing Director of The Anti Corrosion Experts FZ LLC, a leading third-party inspection and consultancy firm specialising in corrosion and coating solutions for offshore, onshore, and EPC projects. He also serves as a senior coatings and corrosion consultant, supporting oil and gas operators, paint manufacturers, ship owners and shipyards. His responsibilities include independent coating inspections, specification review, QA/QC audits, technical consultancy, and training, ensuring strict compliance with NORSOK, ISO, ASTM, SSPC/NACE, and other international standards.

1. Introduction

Surface condensers are vital to marine steam-cycle operation, supporting turbine vacuum performance and condensate recovery.

Their auxiliary components, however, often operate under

mixed-phase, moisture-retaining conditions that are not routinely monitored. The vent pipe is one such component. Its primary function is to evacuate non-condensable gases from the condenser shell, preserving vacuum quality and preventing efficiency losses.

Despite its size, the vent pipe experiences a demanding environment. Steam air mixtures cool rapidly within the line, producing intermittent condensate formation. During low-load operation, condensate accumulation is more likely, allowing stagnant moisture to remain in contact with carbon steel surfaces. If seawater vapour or entrained marine organisms enter the system through leakage or inadequate filtration, the internal environment becomes increasingly favorable to localised corrosion and MIC.

These processes may progress undetected until significant wall loss or perforation occurs.

The failure examined in this article was identified during routine shipyard maintenance. A section of the vent pipe was removed for examination after external abnormalities were noticed.

Internal inspection revealed complex patterns of corrosion and biological settlement. The findings underscore the importance of understanding how moisture retention, deposit formation, and microbial activity interact to produce accelerated internal degradation in marine vessels.

2. Operating Function and Environmental Conditions of the Vent Pipe
   
   Role in Removing Non-Condensable

Non-condensable gases such as air and carbon dioxide reduce condenser efficiency by forming insulating layers on heat-transfer surfaces. Their removal depends on the performance of the vent system.

The mass of gas discharged can be estimated using the ideal gas relationship:

Where . is the mass flow rate of non condensables, Pis absolute pressure, Vis gas volume, Ris the specific gas constant, and Tis absolute temperature.
m
 
For example, 0.1 m³ of air at 15 kPa and 40°C yields:

Although this mass is small, the presence of non-condensable significantly affects vacuum stability. Any fouling or corrosion within the vent line that restricts flow can impair condenser performance.

2.2 Moisture Retention and Corrosive Exposure

The vent pipe interior is subject to:

• continuous or intermittent wetting
• stagnation during reduced steam flow
• condensation containing trace chloride species
• organic and inorganic debris
• variable oxygen availability

A key predictor of corrosion is the time-of-wetness (TOW):

Where twrepresents time the surface remains wet, and ttotal is the total exposure time. Marine systems frequently exhibit TOW values above 0.6, indicating high corrosion susceptibility. In vent systems with inadequate drainage, TOW approaches unity, enabling persistent localized attack and supporting microbial colonisation.

3. Component Description and Service Conditions

The component analysed was a carbon steel vent pipe, likely conforming to ASTM A106 Grade B, with an original wall thickness of approximately 3.0 mm. The line had operated for several years without internal cleaning or inspection. No internal coating was applied, and the pipe’s geometry allowed condensate pooling at specific locations.

During shipyard maintenance, the removed section was found heavily fouled with marine organisms and corrosion products.

Post-cleaning UT measurements revealed minimum remaining thicknesses as low as 0.8 mm. This indicated pronounced localised thinning consistent with pitting and MIC.

The absence of internal protection, combined with intermittent flow and poor drainage, created favourable conditions for corrosion initiation and propagation. The presence of barnacles and biofilms suggested that seawater entrainment and inadequate filtration played a role in introducing biological contaminants.

4. Observations and Corrosion Morphology

The internal surface showed a clear transition between regions affected only by general corrosion and zones heavily colonised by marine organisms. This provided a direct comparison of corrosion behaviour under different microenvironments.

Figure 1: General Oxidation in Non-Fouled Areas.

Non-fouled areas exhibited uniform reddish-brown corrosion and darker patches of magnetite, typical of oxygen-limited wet-dry cycling.

Figure 2: Barnacle Colonisation and Calcareous Deposits.

Barnacle bases strongly adhered to the steel surface, forming rigid crevice-like structures. These deposits retained moistur and created localised oxygen differentials that promoted under-deposit attack.

Pits were sharp-walled and deep, often containing black corrosion products associated with MIC, such as iron sulfide.

6.3 Crevice Corrosion

Flange interfaces and barnacle bases acted as natural crevices. Differential aeration accelerated anodic dissolution internal to the crevice.

6.4 Microbiologically Influenced Corrosion (MIC)

Several features—blackened deposits, sulphide films, and pit morphology—suggested MIC driven by sulfate-reducing bacteria (SRB). The fundamental reaction:

produces iron sulfide films, contributing to aggressive localised attack.

6.5 Biofouling-Assisted Corrosion)

Barnacles and biofilms created semi-sealed microenvironments that impeded oxygen transport, trapped nutrients, and supported anaerobic microbial communities. Their role as long-term moisture traps amplified both pitting corrosion and MIC.

7. Discussion of Interacting Environmental Factors

The corrosion patterns indicated strong dependence on biological presence. Areas without barnacle attachment exhibited moderate general corrosion, while fouled areas suffered severe pitting and MIC. This contrast highlights the influence of biological settlement on corrosion kinetics.

Three primary stages of degradation were identified:

1. Ingress and survival of larvae and microorganisms due to insufficient seawater filtration.
2. Settlement and colonisation within stagnant condensate, especially during low-load operation.

3. Establishment of anaerobic niches beneath deposits, supporting MIC propagation and high pitting rates.

Additionally, wet-dry cycling intensified oxidation reactions. As the vent pipe sits near the condenser top, surfaces frequently transition between condensation and drying, accelerating corrosion.

8. Summary Assessment

 The combined evidence supports the following deterioration mechanisms:

• High time-of-wetness due to stagnant condensate
• No internal coating to protect carbon steel surfaces
• Introduction of biological organisms via process contamination
• Formation of barnacle bases and biofilms acting as corrosion incubators
• MIC accelerating localised attack
• Crevice geometries amplifying differential aeration
• Lack of internal cleaning or inspection opportunities
• Limited drainage due to suboptimal pipe orientation

These factors acted together over the service period, resulting in significant wall thinning and risk of failure.

9. Engineering Recommendations

 9.1 Material Upgrade

Consider replacing carbon steel with duplex or super duplex stainless steel for improved resistance to pitting, crevice corrosion, and MIC.

9.2 Internal Protective Coatings

Apply epoxy or fusion-bonded epoxy coatings to reduce moisture retention and inhibit biofilm adhesion.

9.3 Drainage Enhancement

Apply epoxy or fusion-bonded epoxy coatings to reduce moisture retention and inhibit biofilm adhesion.

9.4 Improved Filtration

Upgrade seawater filtration to prevent larvae and particulate ingress.

9.5 Biocide Control

Use automated dosing of oxidising or non-oxidising biocides to manage microbial populations.

9.6 Routine Access and Inspection

Incorporate inspection ports or removable sections to allow periodic internal examination.

10. Conclusion

This case study demonstrates how internal corrosion within vent piping can evolve rapidly when biological and environmental factors align. Barnacle settlement, biofilm growth, stagnant condensate, and MIC collectively produced severe pitting and wall loss exceeding 70 percent.

Without intervention, such degradation can compromise condenser performance and overall vessel integrity. Implementing improved materials, suitable coatings, drainage, filtration, microbial control, and systematic inspections will significantly reduce future risk and enhance reliability of marine steam-cycle systems.

References

1. M G Fontana, Corrosion Engineering, 3rd , McGraw-Hill, 1987.
2. A J Sedriks, Corrosion of Stainless Steels, 2nd , Wiley-Interscience, 1996.
3. B Little and J Lee, Microbiologically Influenced Corrosion, Wiley,
4. ASM Handbook, Volume 13B: Corrosion: Materials, ASM International,
5. W Revie and H H Uhlig, Corrosion and Corrosion Control, 4th , Wiley-Interscience, 2008.
6. ASTM G1-03, Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens, ASTM International.
7. ASTM G48-20, Standard Test Methods for Pitting and Crevice Corrosion Resistance of Stainless Steels and Related Alloys by Use of Ferric Chloride Solution, ASTM International.
8. ASTM G46-94(2018), Standard Guide for Examination and Evaluation of Pitting Corrosion, ASTM International.
9. NACE SP0775-2013, Internal Corrosion Control of Submerged Pipeline Steel Line Pipe, NACE International.
10. ISO 8501-1:2007, Preparation of Steel Substrates Before Application of Paints and Related Products: Visual Assessment of Surface Cleanliness, International Organization for Standardization.
11. NORSOK M-501 (2018), Surface Preparation and Protective Coating, Standards
12. ASTM A790/A790M-20, Standard Specification for Seamless and Welded Ferritic/Austenitic Stainless-Steel Pipe, ASTM International.
13. ASTM A312/A312M-22, Standard Specification for Seamless, Welded, and Heavily Cold Worked Austenitic Stainless-Steel Pipes, ASTM
14. A W Peabody and R E Bianchetti, Peabody’s Control of Pipeline Corrosion, 2nd and 3rd ed., CRC Press, 2018.
15. R E Melchers and R Jeffrey, “Corrosion of long vertical steel members in seawater,” Corrosion Science, 2014, 89, pp. 169–184.
16. NACE TM0212-2012, Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion (MIC) on Internal Surfaces of Pipelines, NACE International.
17. NACE/AMPP SP0108-2021, Corrosion Control of Marine Pipelines, AMPP,
18. IUPAC, “Corrosion rate and pitting,” Compendium of Chemical Terminology (the ‘Gold Book’), IUPAC.
19. G Schmitt and W Bruckhoff, Seawater Corrosion Handbook, Elsevier,
20. NACE Conference Archives – Boiler Tube Failure Case Studies, available at: org (accessed 2025).

Chukwuma (Chuks) Onuoha, PhD, P.Eng. FICorr.

Dr Chukwuma (Chuks) Onuoha, P.Eng., PhD is a Principal Corrosion Engineering Lead at Canchuks Corrosion Inc Canada specialising in pipeline integrity, corrosion engineering, and advanced inspection technologies. He holds an MSc in Corrosion Control Engineering from the University of Manchester (UK) and a PhD in Materials Engineering (corrosion specialisation) from Dalhousie University (Canada). He has led major integrity programmes including ECDA, ICDA, and SCCDA across complex pipeline systems worldwide. Dr Onuoha has authored over 50 technical papers and actively collaborates with industry research organisations to advance emerging integrity technologies. He is an AMPP Certified Corrosion Specialist and a Fellow of the Institute of Corrosion (ICorr). With more than a decade of hands-on involvement in Contactless Magnetic Inspection Technology (CMIT), he has supported its development, validation, and deployment across multiple continents. His work focuses on improving inspection confidence, reducing uncertainty in integrity decisions, and enhancing the reliability and safety of high-risk pipeline infrastructure.

Author Experience Statement – Contactless Magnetic Inspection Technology (CMIT)

This article is written based on the author’s direct personal and professional experience in the research, development, validation, and global deployment of Contactless Magnetic Inspection Technology (CMIT). Dr. Onuoha has been actively involved in CMIT technology development, pilot programs, and full-scale operational deployment for over a decade. During this time, he has supported and led CMIT applications across North America, Europe, Africa, and the Middle East, gaining extensive real-world insight into the technology’s capabilities, limitations, and optimal deployment strategies.

Through this work, Dr. Onuoha has personally validated the use of CMIT across multiple integrity applications, including:

• Detection and characterization of internal corrosion, external corrosion, and stress corrosion cracking
• Optimization of excavation programs by refining external corrosion assessment dig prioritization
• Support of pipeline integrity investigations and failure analysis programs
• Evaluation of cased pipeline crossings and complex buried pipeline geometries
• Integrated integrity assessments combining cathodic protection performance, coating condition, and CMIT inspection data
• Detection of corrosion and strain-related anomalies in cathodically protected pipelines with high-shielding dielectric coatings
• Assessment of geohazard-related strain signatures affecting buried pipelines

The technical perspectives presented in this article are grounded in practical field deployments, engineering analysis, and direct technology application across diverse operating environments. As such, the framework and conclusions presented are based not only on theoretical understanding, but on demonstrated operational performance and real-world integrity outcomes.

Deployment of Contactless Magnetic Inspection Technology (CMIT) for the Integrity Assessment of Unpiggable Pipelines

Buried pipelines that cannot be inspected using conventional in-line inspection (ILI) tools, commonly referred to as unpiggable pipelines, remain among the most challenging assets to manage within modern pipeline integrity programs. Design limitations, diameter restrictions, flow constraints, operational interruptions, legacy construction features, and economic considerations frequently prevent the deployment of ILI technologies.

Some of the reasons why some buried pipelines cannot be internally inspected (Pigged) include:

• Small Diameter Pipelines
• Non-Piggable Pipeline Geometry
• Absence of Pig Launchers and Receivers
• Diameter Changes (Reducers / Expanders)
• Flow Constraints
• Low Pressure or Intermittent Service
• Internal Restrictions or Obstructions
• Multiphase or Unstable Flow Regimes
• Operational Risk or Inability to Interrupt Service
• Legacy Construction Features
• Economic Constraints
• Product or Service Limitations

Consequently, operators are often required to make critical integrity decisions for ageing, high-consequence assets with limited direct condition data and increased reliance on indirect indicators. In response to these limitations, the industry has traditionally adopted direct assessment (DA) methodologies, specifically, external corrosion direct assessment (ECDA), internal corrosion direct assessment (ICDA), and stress corrosion cracking direct assessment (SCCDA), to manage unpiggable pipelines. While DA frameworks are well established and supported by industry standards, they are fundamentally inferential

in nature. They depend heavily on historical records, environmental parameters, system-level indicators, and engineering judgement to infer the presence, severity, and location of integrity threats. This reliance introduces inherent uncertainty, particularly in complex operating environments where multiple degradation mechanisms interact or where geotechnical conditions evolve over time. As regulatory expectations increasingly emphasise performance-based integrity management and defensible, data-driven decision-making, the limitations of direct assessment techniques (especially indirect inspection) have become more pronounced. There is a growing demand for aboveground inspection technologies capable of providing pipeline-specific, inspection-grade condition data without requiring excavation, coating removal, service interruption, or physical contact with the pipe.

Contactless magnetic inspection technology (CMIT) represents a significant advancement in this regard. CMIT is a non-intrusive, indirect, above ground inspection technology that assesses the condition of buried ferromagnetic pipelines by measuring localised disturbances in the Earth’s naturally occurring magnetic field. These disturbances arise when changes occur in the pipeline’s structural or mechanical state, including localised wall-thickness loss, residual or applied stress, plastic deformation, or geometric irregularities. By deploying high-resolution magnetic sensors along the pipeline right-of-way, CMIT captures, quantifies, and interprets these anomalies to provide a direct indication of pipeline integrity without the need for physical access to the asset.

Unlike conventional above-ground survey tools that rely primarily on surrogate indicators, such as coating condition, cathodic protection performance, or soil resistivity, CMIT responds to the physical manifestation of degradation and deformation within the pipeline steel itself. This distinction allows CMIT to bridge the gap between indirect assessment and direct inspection, offering actionable integrity intelligence that is both pipeline-specific and engineering-relevant. The non-contact nature of the technology makes it particularly well suited for long-distance pipelines (for instance, over 5 km), environmentally sensitive regions, congested rights-of-way, and high-consequence areas where excavation is disruptive, costly, or impractical.CMIT operates through the continuous measurement of magnetic field deviations relative to the background geomagnetic field. These deviations may originate from a range of integrity threats, including:

• Corrosion-related metal loss, both internal and external,
• Crack-like defects and stress concentration zones associated with progressive stress,
• Corrosion cracking (SCC),
• Weld anomalies and fabrication-related discontinuities,
• Geometric deformations such as dents, wrinkles, buckles, or ovalities,
• Localised strain and deformations resulting from geotechnical activity, including landslides, subsidence, frost heave, or lateral soil

By translating these non-contact magnetic signatures into interpretable engineering indicators, CMIT enables operators to directly identify and prioritise integrity threats that would otherwise remain concealed beneath intact coatings or undisturbed soil. Figure 1 shows CMIT operation in action.

Strengths of CMIT in Defect Detection

Corrosion Metal Loss Detection

One of the primary strengths of CMIT is its ability to detect corrosion and metal loss. Because magnetic field disturbances are directly influenced by changes in wall thickness, CMIT can identify sites of localised thinning caused by both internal and external corrosion mechanisms. This capability is particularly valuable in scenarios involving disbonded or shielding coatings, where conventional external corrosion assessment techniques (direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), and cathodic protection close interval survey (CIPS)) cannot provide reliable indications of the pipe-wall condition.

Crack and Stress Corrosion Cracking (SCC) Detection

CMIT also demonstrates sensitivity to stress concentration zones associated with crack initiation and propagation, including SCC. Magnetic distortions arising from localised strain accumulation provide insight into regions that may be susceptible to SCC, offering the potential for earlier identification of high-risk areas compared to traditional surface surveys alone.

Mechanical Threat Identification

In addition to corrosion and cracking, CMIT can identify mechanical integrity threats such as dents, buckles, wrinkles, and ovalities. These features generate characteristic magnetic signatures that can be detected and spatially resolved, allowing operators to assess mechanical damage that may compromise structural integrity or accelerate fatigue and crack growth.

Geohazard Interaction Monitoring

A particularly compelling application of CMIT is in the detection and monitoring of pipeline interactions with geohazards. Geotechnical threats, including landslides, erosion, flooding, frost heaves, thermal expansion, subsidence, and seismic activity, can impose bending, axial strain, and localised deformation on buried pipelines. These mechanical responses induce measurable magnetic field anomalies that CMIT can detect along the pipeline right-of-way, providing an early indication of geohazard-related stress before visible surface damage or failure occurs.

For unpiggable pipelines, the challenge of managing geohazard risk is especially acute. Existing approaches rely largely on localised geotechnical investigations, aerial or satellite monitoring, and selective excavations, each of which may fail to capture subtle subsurface pipeline strain or provide continuous pipeline-specific insight. CMIT addresses this gap by enabling the identification of deformation and strain signatures that are characteristic of pipeline-geohazard interactions, thereby supporting proactive mitigation and risk-informed integrity decision-making.

Figures 2 – 3 show the spatial presentation of prioritised anomalies and identification of a stress concentration zone on a pipeline subjected to a stress-deformed state.

Figure 2: Spatial Presentation of Prioritised Anomalies [1].

Figure 3: Identification of Stress Concentration Zone on a Pipeline Subjected to a Stress-Deformed State [2].

Figure 4: Identification of Stress Concentration Zone on a Pipeline Subjected to a Stress-Deformed State [2].

Integrated Pipeline Integrity Approach with CMIT

Collectively, the integration of CMIT within established DA frameworks represents a decisive shift toward a more evidence-based, performance-driven integrity paradigm for unpiggable pipelines (Figures 5 and 6).

Figure 5: The Synergistic Relationship of CMIT with CP CIPS, DCVG and ACVG in the Integrity Assessment of Unpiggable Pipelines [1, 3].

Figure 6: Integration of CMIT with DA Methodologies [4 – 9].

By delivering inspection-grade, aboveground data that directly reflect corrosion, cracking, mechanical deformation, and geohazard-induced strain, CMIT substantially reduces the uncertainty inherent in ECDA, ICDA, and SCCDA methodologies, transforming predictive assumptions into verifiable engineering insights. CMIT’s non-intrusive, repeatable deployment enables efficient assessment across remote, environmentally sensitive, and high-consequence locations without disrupting operations or critical infrastructure, while its geo-referenced outputs seamlessly integrate with GIS, historical DA records, and adjacent ILI datasets.

This convergence of technologies enhances anomaly detection confidence, optimises excavation decisions, and minimises unnecessary digs, ultimately strengthening regulatory defensibility and operational efficiency. As pipeline systems continue to age and regulatory expectations evolve, CMIT-enabled integrity programmes provide operators with a scalable pathway from reactive threat management to predictive, proactive stewardship, thereby extending asset life, reducing risk, and establishing a new benchmark for the modern integrity management of non-ILI assets.

Practical Deployment of CMIT in the Integrity Assessment of Buried Unpiggable Pipelines

Figure 7 presents a recent CMIT case study conducted on a buried 20-inch natural gas pipeline coated with high-density polyethylene (HDPE) tape.

Figure 7 (a): Direct Examination Photos After Coating Removed and Pipe Blasting [1].

Figure 7 (b): Direct Examination photos

 This case study illustrates the practical deployment of CMIT under conditions that are widely recognised across the industry as particularly challenging for conventional integrity assessment methodologies.

High-dielectric, shielding coating systems, such as polyethylene tape coatings that are improperly applied or have degraded over time, are known to electrically isolate disbonded regions of the pipeline from the surrounding electrolyte. This electrical isolation can significantly impair the effectiveness of cathodic protection (CP) systems by preventing sufficient protective current from reaching the steel surface beneath the coating. As a result, localised external corrosion may initiate and propagate undetected beneath the disbonded coating, even while CP survey data continue to indicate apparent compliance with established protection criteria. Under such conditions, traditional indirect inspection tools, including CP monitoring, DCVG, and CIPS, are inherently limited in their ability to reliably detect or confirm active corrosion beneath shielding coatings.

CMIT overcomes these limitations by directly sensing magnetic field disturbances associated with changes in pipe wall thickness, stress concentration, and localised deformation from aboveground, without reliance on electrical continuity or direct contact with the pipeline.

Because CMIT responds to the physical manifestation of corrosion and stress within the steel itself, it provides a direct and independent means of identifying degradation beneath disbonded or shielding coatings. This capability positions CMIT as a powerful complementary technology to CP-based monitoring and conventional indirect inspection surveys, offering operators an additional layer of confirmation regarding actual pipeline condition.

Case Study 1 demonstrates the effectiveness of CMIT in identifying zones of coating disbondment and active external corrosion that were not evident through routine CP data alone. The CMIT results correlated with subsequent field verification, confirming the presence of external corrosion beneath the HDPE tape coating and validating the reliability of the technology as a diagnostic tool for buried, cathodically protected pipelines. A key advancement illustrated by this case study is CMIT’s demonstrated ability to detect external corrosion on pipelines protected by High-dielectric, shielding coating systems a long-standing challenge that has historically limited the effectiveness of external corrosion assessment programmes.

For operators managing buried, unpiggable pipelines, particularly those coated with shielding systems, CMIT provides a transformative pathway for identifying external corrosion and SCC threats that would otherwise remain undetected. When integrated within established DA frameworks, CMIT enhances anomaly detection accuracy, improves excavation prioritisation, and strengthens the technical defensibility of integrity decisions. Ultimately, the application of CMIT in these challenging environments contributes to improved pipeline safety, reduced uncertainty in integrity assessments, and a more robust, performance-based approach to managing non-ILI assets.

CMIT Case Study 2: High-Confidence Detection of Complex Defect Clusters in an Unpiggable Crude Oil Pipeline

In a recent field deployment, CMIT demonstrated exceptional accuracy in identifying and characterising a complex cluster of interacting anomalies along a 30-m (100-ft) section of a 10-inch crude oil transmission pipeline. Unlike even the most advanced ILI tools, which rely primarily on geometry-based measurements and physical access, CMIT is a fully contactless magnetic inspection technology capable of detecting both internal and external defects by sensing disturbances in the pipeline’s natural magnetic field. These disturbances arise from changes in magnetic permeability caused by corrosion, mechanical damage, deformation, bending strain, and crack precursor activity within the steel microstructure.

From an economic perspective, the cost differential between conventional ILI deployment and non-invasive CMIT inspection can be substantial. For pipelines that are not currently piggable, enabling ILI often requires installation of pig launchers and receivers, system modifications, and operational adjustments. In many cases, pipe pre-clearing activities are also required to remove debris, wax, scale, or deposits to ensure safe and effective tool passage. These activities are typically followed by multiple cleaning runs, gauging runs, and baseline ILI runs before usable integrity data can be obtained. Additional costs may include production impacts, temporary shutdowns, engineering studies, and operational risk management.

When these cumulative costs are considered, total ILI enablement and execution costs can be on the order of magnitude of approximately 20X compared to a baseline non-invasive CMIT inspection cost (1X), particularly for legacy or operationally constrained assets. In contrast, CMIT can be deployed without pipeline modification, product removal, or operational interruption, providing inspection-grade data while significantly reducing cost, schedule, and operational risk exposure.

Using high-resolution magnetic sensors, CMIT captured a continuous and elevated magnetic response across the full 30-m segment, indicating the presence of multiple interacting degradation mechanisms rather than isolated defects (Figure 8).

Figure 8 (a): Preliminary Sections of Exposed Pipeline Confirming Defects.

Figure 8 (b): Preliminary Sections of Exposed Pipeline Confirming Defects.

Case Study Outcomes

The technology successfully resolved signatures associated with continuous external corrosion metal loss, localised pitting and wall thinning, mechanical denting, ovality, long-seam strain, and residual stress accumulation. Because CMIT does not depend on piggability, flow conditions, or internal access, it is uniquely suited for operationally constrained or unpiggable pipelines where traditional ILI solutions are not feasible.

Based on the CMIT results, the identified pipeline segment was excavated for direct examination. At the time of reporting, abrasive blasting, surface preparation, and non-destructive examination were still in progress; however, early visual inspections had already confirmed the presence of continuous external corrosion, mechanical deformation, localised bending and strain, and surface features consistent with long-term coating disbondment and underfilm corrosion. These findings directly correlated with the moderate-to-severe CMIT response recorded prior to excavation.

The strong agreement between CMIT data and preliminary field observations validates the technology’s sensitivity to complex, multi-mechanism defect clusters and its ability to accurately map defect extent, severity, and interaction. Critically, CMIT enabled the operator to recognise a long, continuous zone of degradation that would not have been identified with comparable confidence using indirect assessment techniques alone. This level of insight is essential for understanding true integrity risk and for making defensible, risk-informed decisions.

Upon completion of a detailed NDE and engineering evaluation, appropriate mitigation measures, including recoating, reinforcement sleeves, localised repairs, stress-relief actions, or section replacement, will be implemented. The high-confidence, pre-excavation intelligence provided by CMIT allows these interventions to be precisely targeted, technically justified, and safety-focused.

In summary, this case study clearly demonstrates CMIT’s value as a deployable, inspection-grade solution for the early detection of complex defect clusters, enabling proactive intervention and significantly enhancing the safe and reliable operation of crude oil pipelines

Conclusions

This study demonstrates that CMIT provides a substantive advancement in the integrity management of unpiggable pipelines by overcoming key limitations of indirect-only assessment approaches. Field-validated case studies confirm CMIT’s ability to detect and characterise external corrosion, SCC-related stress concentrations, and complex interacting defect clusters, including degradation occurring beneath high-shielding dielectric coatings. The strong correlation between CMIT responses

and direct examination findings validates its sensitivity to defect extent, severity, and interaction, delivering inspection-grade insights beyond conventional DA methods.

When integrated within ECDA, ICDA, and SCCDA frameworks, CMIT reduces uncertainty, improves excavation prioritisation, and strengthens the technical defensibility of integrity decisions.

Collectively, CMIT establishes a deployable, non-intrusive, performance-based solution that enhances pipeline safety, supports proactive mitigation, and sets a new benchmark for the aboveground assessment of non-ILI assets.

References

1. C Onuoha, “No contact, no problem: validating contactless magnetic inspection for corrosion detection on buried gas pipelines,” Paper C2026-00291, in Proceedings of the AMPP Corrosion Conference 2026, AMPP, Houston, TX.
2. C Onuoha, “Innovative non-contact overline survey techniques for the water and wastewater industry,” Paper No. C2025-00220, in Proceedings of the AMPP Corrosion Conference 2025, AMPP, Houston,
3. C Onuoha, “Coating anomaly detection with integrated indirect inspection tools,” Paper C2019-12810, in Proceedings of the AMPP Corrosion Conference 2019, AMPP, Houston, TX.
4. C Onuoha, “Successful deployment of contactless magnetic inspection technology (CMIT) for the prioritisation of external corrosion engineering assessment (ECEA) digs,” Paper 10, in Proceedings of the AMPP Calgary Corrosion Conference 2026, AMPP.
5. T Xu, “Understanding quantitative performance of large standoff magnetometry in detecting live gas pipeline anomalies with stress estimation,” in Proceedings of the International Pipeline Conference, Vol. 51869, Paper No. V001T03A020, ASME.
6. S McDonnell, “Identifying stress concentrations on buried steel pipelines using large standoff magnetometry technology,” in Proceedings of the International Pipeline Conference, 51869, Paper No. V001T03A003, ASME.
7. S McDonnell, “Improved methodology for identification of buried casings using indirect inspection method,” Paper C2017-9400, in Proceedings of the AMPP Corrosion Conference 2017, AMPP, Houston, TX.
8. C Onuoha, “Advancements in stress corrosion cracking direct assessment using an integrated approach,” Paper C2018-11194, in Proceedings of the AMPP Corrosion Conference 2018, AMPP, Houston, TX.
9. E Pozniak, “Use of large standoff magnetometry in pipeline integrity investigations,” Paper C2020-14475, in Proceedings of the AMPP Corrosion Conference 2020, AMPP, Houston, TX.

Meet The Author

Neil M Cowin, MSc, CEng

Neil M Cowin is an experienced Integrity Manager specialising in topsides facilities, pipelines and subsea engineering, with a strong focus on corrosion and HSE management. An innovative thinker with extensive experience delivering strategic, operational and technical integrity services for large-scale offshore and onshore assets. Possesses in-depth expertise in process and operational integrity, inspection, maintenance, corrosion engineering, materials selection and integrity consultancy for pressurised systems, including subsea facilities, pipelines and topsides.

Highly skilled in technical data acquisition for integrity, inspection and maintenance planning, and in the development and consolidation of equipment databases. Demonstrates strong knowledge of inspection policies, procedures, scopes and methodologies, including risk-based inspection systems and written schemes of examination. Acts as Technical Authority for pressure systems and provides specialist input to EPC design reviews. Experienced in CP design and retrofit programmes, defect assessment, fracture mechanics, remaining life assessments and repairs in accordance with API 579, PD 5500 and ASME VIII.

Introduction

Subsea inspection has developed NDE equipment from those techniques developed for the inspection of pipelines and piping for topside oil and gas service. Especially techniques such as automated UT, ACFM, Eddy Current, Pulsed eddy current, radiography, Acoustic Resonance [ART], now CT – radiation scanning Tomography for deepwater pipelines at 3000m water depths even was utilised subsea to some extent. New developing techniques, per thermography and CT tomography, are also now employed to achieve data for inspection of pipelines and have been useful for inspection of bundles for subsea service. These techniques have also been developing to allow inspection of flexibles to some degree of success, and this is ongoing.

The issues have also related to the factor that external coatings are to be removed to allow such inspection for certain techniques especially that for automated UT. This is because UT cannot define defects below insulative coatings and FBE. The power requirements for ultrasound are the main restriction for not allowing signals to be received from the substrate below coatings such as 3 layer or cement clad pipelines with carbon steel ROD reinforcement cages within the cement cladding upon the pipelines.

All techniques have to be developed and managed via a surface vessel and supported by ROV’s in the main to allow inspection below water. The depths range but presently inspection can bemanaged up to 250 m depth pipelines for the majority of the techniques and for ‘CT-Scanning radiation Topography’ the equipment is viable to 3000 m water depth at significant cost. Thus, analysis is called upon to enable definition of the NDE techniques which will lend themselves to allow inspection of pipelines subsea as a screening approach without removal of external coatings and allow inspection of the WET through FBE, 3-layer coatings and also cement clad weight coated pipelines.

It is to be recognised that 80% of pipelines are non piggable and thus ILI as a method for inspection on many occasions is not viable subsea without expensive modifications, e.g. temporary pig traps (subsea or portable constructed on topsides).

Methodology Outlining the Status of Subsea NDE and Further Requirements

The initial trial inspections were based upon NDE techniques as stated surrounding topside and onshore piping inspections. These being based upon ASME section V standards capabilities and API 571.

These were ‘UT’, ACFM, Eddy Current then moving forwards to Pulsed Eddy Current, Automated UT arrays, Eddy Current arrays, development of a radiography tool then recent periods have witnessed ‘CT- radiation Tomography’ and also developing Thermography being utilised as a subsea inspection. The other advancements has been ‘ART’ the Acoustic resonance UT array technology.

It began with use of divers and moved forwards to the use of ROV’s and surface vessel management and scope developments. The stated crux is that external coatings mainly have to be removed, which often causes concern. Techniques have advanced with ‘ACFM’ and ‘Eddy Current’ and specialistic Pulsed Eddy current and newer developed CT- radiation Tomography which has allowed WT of the pipelines to be assessed without the removal of coatings.

It has to be stated that the goal is to achieve a screening protocol of investigation of subsea pipelines without coatings removal in the
long term. The development of ‘ACFM’ (alternating current field measurement) has been born from its usage with structures inspection for defining flooded members for offshore jackets which is a standard inspection undertaken at defined frequencies with the assistance of ROV’s and an inspection vessel. Initial inspections using automated ‘UT’ again are defined by assessment by RBI across the seabed review of the most likely sites where coatings can be removed in 3m sections to allow a ‘UT’ array tool to be attached and rotated around the pipeline up to 3 or 5m sections is the normal status.

Pulsed Eddy Current (PEC)

PEC subsea inspection is used to detect and map corrosion and general wall thinning in ferrous metal assets, such as offshore risers, pipelines, and submerged structures.A probe with a coil is placed on the surface of the asset being inspected.

The coil creates a magnetic field that passes through any layers of coating, insulation, or marine growth to the metal component. The current is then quickly shut off, causing a sharp drop in the magnetic field. This sudden change creates eddy currents within the pipe wall. The eddy currents spread inward and decay. The rate at which they decay is measured by the probe. A thinner wall (due to corrosion) will cause the eddy currents to decay faster, while a thicker wall will cause them to decay more slowly. This provides a reliable estimate of the remaining wall thickness.

The benefits and features that make PEC a developing NDE technique for subsea pipelines and structures inspections includes No surface preparation: The technique can penetrate concrete weight coatings, thick insulation, and marine growth, eliminating the need for costly and time-consuming cleaning.

• Automation and accuracy: Automated systems and array technology enable consistent performance, improved probability of detection, and highly accurate positioning.

• Efficiency: It allows for rapid, quantitative screening and corrosion mapping of large areas without shutting down production. • Remote deployment: Subsea PEC systems are often mounted on remotely operated vehicles (ROVs) for deep offshore inspections, reducing the need for divers.

• Versatility: The method is effective for a wide range of underwater assets, including pipelines, risers, caissons, and underwater storage tanks.

As an example of pulsed Eddy current underwater probe capabilities. Underwater probes can tackle offshore inspection applications, even through marine growth requiring no surface preparation. The standard underwater PEC probes are watertight to 100m (330 ft) deep and feature a long cable. These probes are operated with the proven PEC system.

The status LEDs embedded in the probes ensure better control and synchronisation of the diver with the topside inspection team. Diver deployed inspectors can scan components as thick as 100 mm (4 in) as well as insulation and marine growth as thick as 300 mm (12 in).

It is understood the critical importance of maintaining the integrity of underwater assets. That’s why underwater pulsed eddy current probes are designed and built to the highest standards of quality and reliability. With advancing ‘PEC’ inspection solutions,’ PEC’ can detect corrosion and defects in underwater structures quickly and accurately, ensuring the safety and longevity of subsea structures and assets. There are now viable ‘PEC’ Technologies for the most advanced, effective, and dependable inspection challenges available in underwater environments.

Figure 1: Example of ROV Conducting a PEC NDE Inspection on the External Surface of a Cement Clad Pipeline.

The ACFM (Alternating Current Field Measurement) subsea crawlers offer smart deployment and operation:

– Motorised mechanisms allow the probe to be deployed accurately over the weld to be inspected.
– Can be deployed by ROV or via deck launch
– Can be deployed with ACFM, ART, or PEC
– Has typical inspection speeds of 30mm/s (1.18ins/s), with a multiple pass inspection being 15 mins/m
– Is rated for water depths up to 150m (493ft)
-Can easily manoeuvre on diameters greater than 760mm (30 ins)
– Uses a closed-loop feedback motor control for accurate weld tracking and a uniform scan speed
– Can inspect through paint and other coatings – Is tolerant of residual marine growth.

Figure 2: Example of ACFM Around a Seam Weld Subsea.

Acoustic Resonance – Subsea Operability

Subsea’s ART is its patented, ultra-wideband acoustic inspection technology, which offers penetration and measurement capabilities through coatings, exceeding those of existing inspection technologies. In addition to analysing the material resonances (frequency domain), the technology uses time-of-flight measurements (time domain), which provides accurate external geometry measurements for ovality and dents. ART uses a transducer shooting a broadband (multiple frequency) sound signal toward a target such as a pipe wall. The signal duration is sufficiently long to generate oscillations in the target. As the oscillating target continues to be struck by the sound signal, the resonance greatly amplifies the oscillations. The resonating frequencies (frequency domain) are characteristic of the thickness and material of the target. Attaining accurate data with direct measurement of thickness makes it possible to calculate corrosion rates more effectively and cuts down on the number of inspections that are ultimately required.

Figure 3: Summary of Proficiency of Acoustic AUT Subsea and Capabilities.

CT – Scanning or Computed Tomography by Radiation Scanning Data.

A major development in deepwater pipeline inspection methodology in recent years has been the integration of subsea CT scanning technology. This enables the delivery of critical flow assurance and integrity data without the need to remove the pipeline’s coating. Subsea CT scanning technology offers operators an enhanced understanding of their pipeline, its coating and its process fluids—while allowing the asset to remain fully operational. Using CT technology, an external scan and detailed high-resolution images of the pipe wall can determine precise sizing of wall thicknesses in minutes. Tomographic imaging can identify flaws within a pipe’s walls, pinpoint the location, and assess the volume and density of any material or deposits in the pipe.

A major development for the industry has been the introduction of methodologies and technologies that enable the online inspection of piggable and unpiggable deepwater pipes from the outside without the need to remove protective coatings or shut down production. Usually deployed using an ROV on a variety of pipeline designs, advanced deepwater inspection systems can provide insights on both internal and external corrosion, detect blockages and ascertain flow issues. They offer the industry a solution for pipelines that simply cannot be inspected by traditional means and can avoid intrusion and loss of production while providing a significant reduction in campaign costs.

An example is given below of the CT radiation tomography scanner developed by the vendor for up to 3000 m operations depth, thus 10,000 ft capabilities for placement onto a pipeline and viability through coatings for developing pictures through the cross section noted below. Deployed by ROV and operated by umbilicals for power supply.

Figures 4 and 5 (Inset): CT Thermography Show Extent of Deposit Inside the Pipeline

This subsea pipeline inspection system was designed to deliver accurate material results and distinguish between wax, sand, hydrate, asphaltene or scale deposition within a density differential as low as 0.03 g/cm3. By gathering real-time data on a variety of pipeline integrity issues, including pipeline corrosion, erosion, pitting and wall thinning, modern inspection technologies enable operators to effectively determine the length of time a pipeline can be extended past its original design life. This can help eliminate the operating costs associated with designing a new section of pipeline, recommissioning, pipeline modification, and the time and risks associated with coating removal/reapplication and long and expensive vessel hire.The introduction of advanced fast screening technology can reduce overall scan time by up to 80% in some cases, which means operators can capture more data from a single pipeline inspection to help them improve and enhance the efficiency of existing pipeline models.

Deepwater pipeline inspection systems are often deployed in conjunction with pipeline screening technology to locate blockages
in subsea pipelines, which can be many miles in length. Accurately detecting the location of blockages caused by a buildup of deposits
is an ongoing issue within pipeline operations. Modern technologies can offer flow assurance screening capabilities to identify areas for further investigation and are often deployed as a pre-cursor to the pipeline inspection system. Advanced screening technologies, such as CT Radiation tomography, allow the rapid screening of pipelines
for content and deposit buildup and can provide the capability to screen several kilometres of line at typical speeds of up to 100m
per hour without interruption to production. Non-intrusive with no requirement for pipeline preparations, these technologies can measure flow assurance from the outside of the pipeline, avoiding the need to remove protective coatings. The most advanced screening systems are capable of being deployed at depths of up to 3,000m (10,000 ft) and have been deployed to inspect a wide range of pipe diameters and systems including rigid coated or uncoated pipe, pipe-in-pipe, bundles and flexibles. They can provide a detailed pipeline profile by identifying the mean densities of contents and the volume of material based on measured densities, detecting the location of deposit buildup, measuring the density profile of the pipeline, and analysing any detected anomalies. Once the screening system has located any suspected blockage, the Discovery inspection system can be deployed to accurately characterize the precise type and scope.

Corrosion Types and Threats in Coated Pipelines

Coating Types

• 3-Layer Systems + Cathodic Protection (CP)
• Cement CladdingCoating Tupes
• Fusion-Bonded Epoxy (FBE)
• Primary Corrosion Drivers:
• Produced water retention (with CO2, H2S, scales, and deposits)

Corrosion Threats

Exacerbation by CO2, H2S, and chloride salts.

Microbiologically Influenced Corrosion (MIC): Anaerobic bacteria in risers insulated for waxy crudes Vapor-phase & condensation effects.

Integrity Risks

Cracking risk in 40 c –120 °C temperature range
Damage to outer coatings → ingress of water/salts
High corrosion rates observed on carbon steel (CS) and alloy pipelines and 316L ,plus martensitic and 400 series Cr alloys
Reduced CP protection effectiveness

Inspection History

• Alloy pipeline threats not fully assessed for SCC/CSCC under coatings and insulation
• Early inspections limited (partial UT with sampling boxes in the 1980s–1990s; partial ROV coverage)

Pipelines coated to FBE specs before cement/3-layer systems

NDT Strategies for Non-piggable Pipelines
Objective: Inspect 40-year-old coated subsea lines where pigging is not feasible. Scope: Pipelines, risers, flexibles, bundles

Prioritisation

• Focus on insulated systems (dew point, wax control)
• High-risk streams first (gas & HC production)
• Then secondary streams & utilities

Available NDE Techniques

Automated UT arrays by subsea collars – The external coatings have to be removed for UT automated arrays to be operable.

• Pulsed Eddy Current (PEC) – wall loss through coatings, average 250m water depths are viable.
• Guided Wave UT (LRUT) – long-range screening, coatings have to be removed for access of the array collet to the
• ACFM – crack detection at welds, ROV-deployable, 150m water depths and viable for deeper
• EMAT – corrosion under supports, no NDT couplant needed
• CT- Radiation Topography- deepwater use up to 3000m depth is viable through coatings.
• CP Surveys by ROV inspection vessels – voltage potentials & potential gradients to assess external pipeline coating and anode condition and longevity.
• Flexibles & Bundles: Annulus testing to 30 m depth maximum, fatigue/curvature monitoring over the arch buoys for structural integrity in water depths up to
• Process Data Correlation: Inhibitor performance, water cut, salts, Fe counts, bacteria.

General Guidance and API Standards

Recommended guidance includes:

A Guideline framework for the integrity assessment of offshore pipelines. DNV Technical Report number 44811520 was part of regulator – HSE KP 3 key performance, type 3 assessment circa 2009 onwards. Especially for Riser integrity management and inspections refer DNV-RP-206.

The CRUX of the matter is to design out the threats by ‘process review’ and replace by inspection equipment especially deepwater subsea production to ensure internal pigging requirements. API 571-Damage mechanism affecting fixed equipment It covers ‘NDE’ and specifications. Technically it does cover onshore facilities more so than offshore.

Way Forwards

It is important to develop a progressive R&D program for screening subsea, coated, non-piggable pipelines.

Discussion

Some key outcomes in these processes to date have been:

• Assessment by a topography review of the seabed profile did not always define defects present. For non- piggable pipelines it has proved verys difficult to satisfy all requirements.
• Design basis has generally been to rely on internal inhibition and coatings and core ‘CP’ for
• Flexibles have been difficult to inspect effectively, due to polymer Focus has been on cracking of armour wires. Assessment of flooding of the annular gap is was achieved via a defined vacuum test period inspection technique in standards (note max 30 m depth viability below water).
• Latterly CT-Tomography and recently subsea Thermography has been more valued, as has ‘ACFM’, ‘ECI’ and ‘PEC’ because of its capabilities through % It has advanced even further since.
• Subsea engineers and integrity managers have Utilised ‘ECI’ and ‘UT’ crawlers but removed % coatings from pipelines in majority of cases to obtain a % inspection.
• The ‘NDE’ focus over the last 20 years has been partially

As the oil and gas industry considers exposure to more challenging and deeper environments, the continuous development of innovative technology will be essential in supporting performance improvements.

As exploration and production go deeper, pipelines will likely have to overcome even greater issues than at present when it comes to integrity and flow assurance. Being able to scan and inspect these assets as accurately and as quickly as possible while allowing production to continue will enable operators to make critical informed decisions, safely and efficiently. Great strides have been made in the screening and inspection of deepwater pipelines, making what may have once been regarded as impossible now possible. However, the industry must

continue to push the boundaries of products and services in the pipeline inspection sector to solve the seemingly impossible problems of the future.

Develop ‘NDE’ Technology for screening the ‘WT’ below the external of subsea coated pipelinesesepcially cement coated pipelines.

Figure 7: Project Consideration’s

Conclusions

Subsea Inspection of Non-Piggable Pipelines: Key Challenges & Future Needs: The development of integrity for subsea pipelines external inspection and especially Risers to facilities are core Major threat for gas leaks or oil leaks within the North Sea (onshore & offshore) and other international zones. Developing techniques for NDE have been derived from what is traditional corrosion management inspection techniques from API 571 approach. These techniques noted AUT, Eddy current, PEC and ACFM were utilised on subsea structures for assessment of corrosion and flooded member detection. They were also extensively utilised for inspection of caissons for utilities (sea water lift for fire mains water for deluge) and injection of disposal water. 40 years of data gained mainly by the removal of coatings subsea and inspection by UT arrays or other techniques such as Eddy Current PEC, even percentage of radiography has often been the best solution’ noting that:

• Current practice: is to remove circa 3m to 5 m width bands of external coating in low-lying areas, analyse WT% by NDE mainly automated UT arrays.
• This principally has been applied mainly to 6”–10” flowlines size ranges especially in the Gulf
• Thus, the weight coated pipelines of Cement cladding up to 150mm (5.9”) thick has created

The noted subsea Failures have been linked to process variations, material selection, and limited NDE capability subsea and also requirements for

a screening approach for pipelines coated with 3 layers (polyethylene, polypropylene, PVC and FBE) or more so cement clad pipelines.

Future Needs

Industry requirements continue to develop at a rapid pace.

• Advanced ‘CT-Topography’, Thermography & ‘ACFM’ (beyond welds) have the current viable capabilities for subsea equipment enclosures for 3000 m water depths
• Automated NDE for thicker coatings is a real focus for inspections subsea both for the depths noted and deeper pipelines projects without external coatings removal especially cement clad weight coated
• High frequency ‘PEC’ pulsed eddy current & ‘ECI’ Eddy Current probes, to enable definition and higher accuracy for pipeline ‘WT’ below cement especially and Also to develop subsea equipment enclosures for PEC and ACFM to equally deepwater depths presently 250 m operability and require developed to 3000 m (10,000 ft) water depths.
• Need to explore the viability of Electro-Magnetic Resonance (EMR) for subsea inspections of external coated pipelines as a screening tool to analyse pipeline ‘WT’.

It is ongoing techniques such as Electromagnetics and acoustic resonance and ‘ACFM’ that will require to be advancing with vendors and technologists in the ‘NDE’ forum and certainly the subsea engineering forum can supply these advancements to the required pipelines and structures to enable a higher definition of screening NDE equipment subsea for the oil and gas industry to enhance and ensure reliability and integrity of pipelines and structures.

References

1. API 571, Recommended Practice for Identifying and Evaluating Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, American Petroleum Institute.
2. ASME Section V, Non-Destructive Examination of Pressure Systems,
3. DNV, Technical Report 44811520: Integrity Assessment of Offshore Pipelines, DNV.
4. DNV-RP-F103, Cathodic Protection of Submarine Pipelines,
5. DNV-RP-F113, Repair Strategy for Subsea Pipelines,
6. DNV-RP-F116, Integrity Management of Submarine Pipeline Systems,
7. PD 8010, Subsea Pipelines, Part 2 and Part 4: Design and Integrity Management of Subsea Pipelines,
8. Practical NDE knowledge from project experience and
9. Presentations and technical details from NDE suppliers within the
10. Technical knowledge of subsea NDE scopes gained over 35

Kevin Harold is a Director at Paintel Ltd. He is a Level 3 ICorr Painting Inspector and Technical Director of Paintel Ltd. and has been involved with painting and coatings for nearly 50 years. Kevin is the retiring Correx Managing Director and also a Correx (Institute of Corrosion) ICATS trainer. During 2025, Paintel was awarded a new Painting / Inspection / Maintenance contract to refurbish and maintain the important Tamar Bridge crossing, running for the next 10 years. The company has maintained the structure since 1999.

Thomas Harold is employed as the Paintel Contracts Manager and is also a Director of Paintel Ltd. He is IPAF & IRATA qualified and an ICorr Level 2 Painting Inspector and ICATS approved Industrial Painting Supervisor with more than 15 years’ experience of applying protective coatings.

Introduction

This article is about the environmental effects and maintenance painting required for ‘Atmospheric Corrosion Control’ on exposed bridge structures and, in particular, the Tamar Bridge linking Devon and Cornwall on the A38 trunk road.

Spanning the River Tamar by the side of Brunel’s famous Saltash railway bridge, the new Tamar Road bridge provided an important new link by road between the City of Plymouth and the county of Cornwall. It was opened in October 1961; it has a total suspended length of around 335 meters plus two side spans and a water-level clearance of between 32 and 35 meters. All in all, a weighty corrosion problem.

Photo: Overview of the Tamar Bridge With Cheery Picker Painting Maintenance Ongoing.

The structure carries around 50,000 vehicles per day in each direction. and is located in a fairly aggressive marine environment, towering over the river Tamar as it flows further into Cornwall in one direction and towards Devonport Dockyard in the other. The bridge has been in continual service since opening, even when it had two cantilevers added and coated during 1999-2000, under the supervision of Paintel.

Corrosivity of Bridge Environment

Its corrosivity classification in accordance with ISO 12944 (the accepted standard that sets out rules for the protection of assets from corrosion by use of coating systems and paint, originally released in 1998) probably ranges between a C4 and C5 (high to very high), plus the effects of the driving Southwest rain and winds, keeping it wet/damp for long periods, and also depending on the geography of the structure, causing corrosion deposits to build up.

The Tamar Bridge’s unique location over the tidal River Tamar and exposure to marine elements means site-specific monitoring and protection are critical for its structural integrity. Engineers conduct routine inspections normally every four months and use advanced techniques including test gauges to measure the depth of corrosion on main cable ropes, to monitor the progression of corrosion.

Challenges and Costs

The bridge’s annual maintenance cost is approximately £2 million, with significant, multi-million-pound projects funded by tolls to specifically address issues like corrosion and deck resurfacing.

As with many similar suspension type bridges, preparation and re-painting of the Tamar Bridge is not without its challenges. When you drive over any bridge you tend to only notice everything at ground/deck level, occasionally you might glance up to the towers and think my goodness that’s high or how on earth do you access that?

Working on tower tops or beams roadside of course involves significant challenges, as does painting beneath the deck level, and that is the case for all types of bridge structures really.

Photo: Distance Harness Assisted Solvent Wash Under Deck.

The steel arrangement beneath deck levels can appear to be very complex and once again your thoughts turn to how would you go about accessing what you might think is particularly inaccessible. Each area not only comes with access challenges but also must address the type and classification of corrosion at any location and how fast it may be progressing, particularly with structurally important fixings and smaller detail areas where corrosion is simply not acceptable.

Maintenance Painting Process and Access

Of course, it would very helpful if you could scaffold a bridge or structure every time maintenance was required or there was a permanent one in place (designed-in), but this can be expensive and time consuming and a quicker fix is often what’s required, providing of course, the quicker fix is acceptable and safe to all.

Access options at the Tamar Bridge do include scaffolds, but only when other methods are considered too dangerous or the works required will be of long duration. The Tamar Bridge has 4 gantries, two main deck and two cantilever gantries; these give access to many locations, but not directly underneath the deck and some other important areas.

Paintel has a MEWP (Mobile Elevating Working Platform)-trained team as well as a RAT (rope access trained) team using rope access methods for preparing, painting, repairing or cleaning surfaces. All these techniques allow us to paint areas that might appear at first to be inaccessible.        

Photo: MEWP (Mobile Elevating Working Platform).

Selective Corrosion Repair Sites

You would have heard people say, “It’s like painting the Forth Bridge; I suppose you start at one end and work towards the other and then start again,” but this couldn’t be further from the truth.  Corrosion is very selective, and the geography and geometry of a structure play a huge part in corrosion risk and corrosion rates, as well as the conditions each part is exposed to. Then add in some contamination, and different types appear: general, pitting, crevice and galvanic, to mention a few.

Corrosion first needs a base metal, steel most commonly, an electrolyte, water, or other, and of course oxygen to corrode/ oxidise any steel. Corrosion areas and rates vary considerably across the structure according to geometry and degree of exposure.

Photo: Bridge Hangar Painting.

Geography and Geometry

High sections (pier/tower tops) are prone to additional exposure, high and low temperatures, intense UV light, continuous wetting and drying, and North, South, East or West perspectives. Of which South dries the most, North dries the least, West is wetter, and East will be cooler; all of these conditions affect corrosion rates.

Many of these areas are accessed by ‘rope access’ methods, as many of the team are IRATA (Industrial Rope Access Trade Association) trained, with a level 3 RAT Team Lead.

Photo: Metal Coating Using A Trug.

RAT work necessitates:

• A Head for Heights
• Exposure to extremes of Climate
• High levels of Fitness

The compensation for operatives is some of the best views a person can have.

Deck/Road Level – Traffic Issues

Exposed, but not the same exposure as the tops of the towers. Higher and lower temperatures. Temperatures can be higher at this level due to radiated heat from the road surface, lower windage and other protection from parapets/tower bottoms and cabins/storage areas. UV intensity remains high, and many surfaces remain wet for long periods due to drainage design with water weepage long after rain has stopped. Contaminated surfaces from traffic activity and the effects of north, south, east or west winds, perspectives all contributing additional corrosion effects.

Temperatures can be lower due to more standing water and ice during the winter and additional shading from piers and storage containers. Surfaces are also wetted and dried continuously with the additional consideration of contaminants.

Pollution from passing vehicles, salt from salt spreaders during winter months, and sludges created by dirt and wet from vehicles that do not dry all add to ongoing corrosion rates and challenges.

Below Deck

These areas are often the most prolific in terms of workload. Much more structural steel is being affected by microclimates. Other factors that influence corrosion rates include being closer to the water/river, rain run-off (from the deck), salt contamination from road salting and bird contamination. Little or no direct sunlight and non-drying of surfaces, sludges and slurry build-up accelerate corrosion rates enormously.

Photo: RAT Based Pressure Cleaning Activities.

Preparation and Painting Specifications

Because of the environmental difficulties associated with blasting, set-up, noise, encapsulation, danger, dust, time factor, clean-up, and spillage, all the preparation prior to painting is done by mechanical preparation standards. This is therefore normally done using small tools like needle guns, grinders, sanders, scrapers, etc., but not before precleaning with degreaser to remove most of the dirt and grease. All surfaces are then prepared to an ISO 8501-1 ‘very thorough’ surface preparation. Once an area of preparation is complete and re-cleaned, it is then inspected for quality control for acceptance. After acceptance, all areas receive a multi-coat paint system of:

The final dry film thickness (DFT) is in excess of 300 microns throughout (higher at spot primed locations).

The paint system being utilised can change depending on prevailing corrosion classification to include additional build with MIO, micaceous iron oxide. The bridge is subjected to a maximum of 6 monthly inspections, sometimes more frequent depending on the site zone, and these inspections flag up the more corroded affected areas, and they become priority work packages. Paint is most usually applied by brush and roller. This avoids problems associated with potential overspray and sheeting issues.

Photo: Incline Cable Painting.

Paint Lifetime Expectancy

In the coating business we often discuss and compare lifetime expectations of different types of preparation and painting techniques. Although many would argue that there is nothing better than blasting prior to painting with all the rules in place, as experienced coating applicators, we have proven ‘year on year’ that if you do thoroughly clean surfaces, prepare to the correct standard and paint to the specification, then this work will also last a very long time, often 10 years plus. Our extensive work on the Tamar Bridge has proved this conclusively.

References

BS EN ISO 12944 (2019) – Multi-part Document –  Corrosion protection of steel structures by protective paint systems.

Bridging The Tamar Visitor Centre | Tamar https://www.tamarcrossings.org.uk

‘Daredevil decorators’ protecting Tamar Bridge from corrosion – BBC https://www.bbc.co.uk

Structural health monitoring of the Tamar suspension bridge | Request https://www.researchgate.net

Tamar Bridge | VolkerLaser. https://www.volkerlaser.co.uk