Ahmad Usman, Group Innovation R&D Engineer, Welding Alloys Group UK

Meet The Author

Ahmad Usman is a Group Innovation R&D Engineer at Welding Alloys Group UK, specialising in high-temperature material degradation in demanding industrial environments. He works with a multidisciplinary team to design alloys that resist corrosion and wear in heavy industry applications. His expertise in thermal spray coatings enables him to address complex challenges through practical, performance-driven solutions. His work focuses on real-world case studies to develop materials that protect critical components and extend service life under extreme conditions.

Ahmad is part of a global research and innovation team committed to technical excellence and supporting industrial partners in advancing their products and services. His research interests focus on the future performance of materials in increasingly aggressive operating environments.

Introduction

Material degradation at high temperature remains a critical challenge across a wide range of industrial sectors, including chemical processing, aerospace, gas turbines, energy generation, refining and petrochemical processing, and metallurgical operations (Spiegel, Zahs, and Grabke 2003). Components operating under such conditions are exposed to reactive gaseous and condensed species, leading to reduced operational efficiency, increased maintenance demands, and ultimately premature component failure. These challenges carry significant economic

and operational consequences, underscoring the importance of understanding and mitigating high-temperature degradation processes (Khantisopon et al. 2022).

The nature and severity of degradation are strongly influenced by the local chemical environment, which is governed by factors such as process conditions, feedstock composition, and deposit chemistry (Corrosion Basics Understanding the Basic Principles and Causes of Corrosion

n.d.). In oxygen-rich environments, protective oxide scales may form and provide a degree of resistance; however, under oxygen-deficient conditions, the stability of such layers is compromised, increasing susceptibility to accelerated attack. The presence of sulphur- and chlorine-containing species further complicates these processes by introducing additional degradation pathways (Floreen and Kane n.d.). Sulphur-rich environments typically promote sulphide formation, while chlorine-containing species can induce active oxidation through the formation and volatilisation of metal chlorides, resulting in rapid material loss (Sadeghimeresht et al. 2018; Usman et al. 2025).

In practical systems, these mechanisms rarely occur in isolation. Instead, they evolve dynamically in response to local variatio in temperature, gas composition, and deposit accumulation, as shown in Figure 1 (Usman et al. 20 As a result, degradation behaviour is often highly heterogeneous, even within a single system, making material selection and lifetime prediction particularly challenging.

Figure 1: Schematic Representation of Corrosion Attack on a Metal Surface.

Although considerable research has been conducted in this field, many studies are based on simplified or controlled environments that do not fully capture the complexity of real operating conditions. Industrial systems exhibit significant spatial and temporal variability, leading to differences in dominant corrosion mechanisms across components.  Addressing this gap requires studies that integrate realworld observations with controlled experimental validation.

The present study adopts this approach by examining three industrial case studies representing distinct chemical environments. The objective is to identify the dominant degradation mechanisms under different conditions and to establish a mechanistic understanding based on post-exposure characterisation of materials and deposits. Alongside this analysis, the study evaluates the performance of thermally sprayed coatings as a mitigation strategy. These coatings offer a flexible and cost-efficient solution for protecting large components, particularly where in situ application is required (Usman et al. 2025). Among the available techniques, arc-sprayed coatings provide a practical balance between performance and deployability. This work therefore investigates the relationship between environmental conditions, degradation behaviour, and coating performance, with the aim of informing the design and selection of protective systems for high-temperature applications.

Industrial Case Studies

Three industrial case studies were selected to examine material degradation under distinct high temperature operating environments. Each case represents a different chemical regime, characterised by variations in deposit composition and gas-phase species, resulting in differences in dominant degradation mechanisms. Material samples were obtained from components exposed to high temperature service conditions. Post-exposure characterisation was carried out to assess both substrate degradation and deposit chemistry. Elemental analysis using scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy (SEM-EDX) enabled identification of key reactive species and their distribution within the deposits and affected material regions.

Case Study 1: Chlorine-Dominated Environment

This environment is characterised by solid-fuel combustion conditions operating at relatively low temperatures (500-600 °C), which favour the condensation and accumulation of highly corrosive molten salt deposits on exposed component surfaces, as shown in Figure 2. Under these conditions, deposited species remain stable in the condensed phase, enabling sustained interaction with the underlying material.

Figure 2: Deposit and Accumulation of Corrosive Deposits on the Exposed Component Surface.

Elemental analysis of surface deposits, as shown in Figure 3, revealed elevated concentrations of chlorine in combination with alkali metals (K, Na), along with iron and oxygen. The presence of alkali chlorides indicates a chemical environment conducive to active oxidation. In this mechanism, chlorine participates in cyclic reactions involving the formation of volatile metal chlorides at the metal-deposit interface. These metal chlorides subsequently migrate outward and re-oxidise in regions of higher oxygen partial pressure, regenerating chlorine species and sustaining the degradation process. This cyclic mechanism disrupts the formation of stable protective oxide layers, leading to accelerated material loss.

Figure 3: SEM-EDX Elemental Analysis of Surface Deposit from the Exposed Material Showing High Concentrations of Chlorine and Alkali Metals (K, Na).

Microstructural observations from the degraded surface (Figure 4) show a porous morphology associated with outward-growing corrosion products. This porous structure is indicative of volatilisation-driven material transport, in which the formation and outward diffusion of metal chlorides result in a non-protective and mechanically weak scale. Elemental distribution maps obtained via EDX analysis (Figure 5) further confirm the localisation of chlorine within these regions, supporting the proposed mechanism of chlorine-driven degradation.

Above: Figure 4: Surface Morphology of Degraded Material Showing a Porous and Outward-Growing Corrosion Product Layer.

Figure 5: SEM-BSE and EDX Maps of Degraded Region Highlighting the Localisation of Chlorine within the Corrosion Products.

Case Study 2: Sulphur-Dominated Environment

In this study, a 310H stainless-steel component operated at approximately 800 °C under a low oxygen atmosphere with high moisture content. The environment contained sulphur-bearing species, including hydrogen sulphide, carbon disulphide, sulphur dioxide, and sulphur trioxide, along with other process-related compounds. Post-exposure analysis revealed significant sulphur enrichment within the degraded regions, accompanied by redistribution of alloying elements such as chromium, iron and nickel.

Microstructural examination (Figure 6) shows the formation of a layered surface scale, with evidence of cracking and localised breakdown. The outer region is enriched in chromium and oxygen, including the formation of a chromium-rich oxide layer; however, this layer appears discontinuous and mechanically unstable, exhibiting fracture and partial spallation.

Elemental distribution maps (Figure 7) further demonstrate that while chromium and oxygen are predominantly concentrated within the outer oxide layer, sulphur has penetrated beneath this layer into the underlying material.

Within these sulphur-enriched regions, iron and nickel remain present, suggesting the formation of sulphide phases within the substrate. This indicates that the protective oxide layer has been compromised, allowing inward diffusion of sulphur species.

Figure 6: Cross-Sectional SEM Micrograph Showing the Layered Oxide Scale Formed on the Exposed Material.

Figure 7: SEM-EDX Maps Illustrating Chromium and Oxygen Enrichment within the Outer Oxide Scale, Alongside Sulphur Penetration into the Underlying Material. The Co-Location of Iron and Nickel within Sulphur-Rich Regions Suggests Internal Sulphide.

 Case study 3: Mixed Chemical Environment

This case study exhibited the simultaneous presence of both sulphur and chlorine-containing species, along with alkali metals, indicating a mixed degradation regime.

Such environments are associated with competing and interacting mechanisms, including sulphide formation and chlorine-induced active oxidation, resulting in complex and often accelerated material degradation behaviour.

Elemental maps (Figure 8) from the degraded metal surface indicate the co-presence of chlorine and potassium within the same regions, suggesting the formation of KCl within the deposited salts. In contrast, sulphur is more widely distributed and associated with iron and oxygen.

Figure 8: SEM-EDX Maps of the Degraded Surface Showing Co-Localisation of Cl and K, Indicating the Presence of KCl within the Deposits. Sulphur is More Broadly Distributed and Associated with Fe-Rich Regions.

 Cross-sectional SEM micrograph (Figure 9) reveals breakdown of the outer oxide scale, accompanied by intergranular attack within the underlying material. The oxide layer appears discontinuous and locally disrupted, reducing its protective capability. Further insight from elemental maps (Figure 10) shows that sulphur, chromium, and potassium are concentrated along the grain boundaries, indicating preferential penetration along these paths. This behaviour suggests that grain boundaries act as fast diffusion pathways, facilitating the ingress of aggressive species and accelerating localised degradation within the material.

Figure 9: Cross-Sectional SEM Micrograph Showing the Presence of Intergranular Attack within the Underlaying Material.

Figure 10: Elemental Distribution Maps Showing the Concentration of Sulphur, Chlorine, and Potassium Along Grain Boundaries, Indicating Preferential Ingress of Reactive Species and Localised Degradation Along These Pathways.

Experimental Procedure and Material

Given the complexity of the three operating conditions identified in the above case studies across different environments, controlled laboratory-scale high-temperature corrosion tests were designed and conducted. This approach was developed to systematically investigate the influence of key variables such as, temperature, exposure time, gas phase composition, and deposit chemistry on the corrosion process.

Arc-Spray Coating

Two cored wire feedstocks were used to deposit coatings via the twin wire arc spraying (TWAS) process (details are reported in a previous study) (Usman et al. 2025). The Ni-based coatings, designated CS-1 and CS-2 (details provided in Table 1), were applied onto 310 H stainless-steel substrate. The coatings were deposited to a thickness of approximately 700 μm.

High-Temperature Corrosion Testing

Corrosion tests were conducted under highly aggressive simulated environments containing CO2, SO2, H2O, O2, HCl, and N2 at temperatures of 550 and 800 ± 5 °C, with exposure durations of 200 h and 300 h. A vertically oriented alumina-lined tube furnace (Figure 11) was used to carry out the high temperature corrosion tests under a controlled atmosphere (Waeytens et al. 2023). Coating samples were evaluated under deposited salt conditions comprising KCl and K2SO4. Before testing, coupon samples and crucibles were ultrasonically cleaned in acetone, followed by drying on a hot plate at 100 °C for 1 h before initial weighing. The combined mass of the crucibles, samples, and deposited salts was recorded to determine the applied deposit quantity.

Table 1: Samples Identification Codes and Experimental Conditions.

Post-Exposure Analysis

Following 200 h and 300 h of exposure, coating samples were assessed through cross-sectional microstructural analysis. Samples were sectioned, cold-mounted in low-shrinkage epoxy resin, and prepared using standard metallographic procedures, followed by polishing to a 1 μm diamond finish using an oil-based system. The cross-sectional microstructures were examined using digital microscopy to evaluate coating integrity, thickness variation, and degradation features.

Dimensional Metrology

Coating performance was further quantified using dimensional metrology to assess material loss and degradation (Waeytens et al. 2023). Thickness measurements were obtained along the perimeter of the exposed coatings. Multiple measurements were collected to ensure statistical relevance, and the data were compared with pre-exposure thickness values. These measurements were used to develop probability models describing coating degradation and to estimate coating lifetime under the tested conditions.

Results and Discussion

Microscopy Image Analysis Cross-sectional optical microscopy was performed on all eight coatings following high-temperature corrosion exposure. The micrographs presented in Figure 12 and Figure 13 indicate that all coatings experienced varying degrees of surface degradation. However, the CS-2 coatings exhibited comparatively lower damage than the CS-1 coatings at both temperatures. At 550 °C (200 h and 300 h), the CS-1 coatings showed pronounced localised attack, leading to the formation of a porous and non-adherent oxide scale. At 800 °C, the degradation was significantly more severe, as evidenced by the development of a highly porous surface morphology and coating delamination after 300 h of exposure. In contrast, the CS-2 coatings formed a relatively uniform and more adherent oxide layer at 550 °C, with only limited pitting observed at isolated locations. At 800 °C, although the severity of attack increased, the coatings continued to exhibit protective behaviour, with no significant spallation or deep interfacial corrosion observed. 

Figure 12: Cross-Sectional Optical Microscopy Images of Samples After Exposure at 550 °C for 200 h (CS-1-2, CS-2-2) and 300 h (CS-1-3, CS-2-3).

Figure 13: Cross-Sectional Optical Microscopy Images of Samples After Exposure at 800 °C for 200 h (CS-1-2, CS-2-2) and 300 h (CS-1-3, CS-2-3).

Dimensional Metrology

Dimensional metrology analysis was used to evaluate the corrosion performance of coating systems by generating statistical distributions of material loss. The median coating loss values (Figure 14) represent the extent of degradation in the exposed specimens. Figure 14 summarises the corrosion performance of coatings CS-1 and CS-2 exposed to simulated environments at 550 and 800 °C. Across all conditions, CS-2 consistently exhibited lower material loss compared to CS-1, indicating superior resistance to high-temperature degradation. For CS-2-2, the median coating loss was approximately 0.4 mm after 200 h at 550 °C, increasing to 1.0 mm after 300 h. At 800 °C, the corresponding values increased to 0.8 mm and 1.5 mm after 200 h and 300 h, respectively. In contrast, CS-1-2 showed significantly higher degradation, with median coating loss values reaching 5.0 mm after 200 h and 7.9 mm after 300 h at 800 °C.

Figure 14: Median Coating Loss of KCl + K2SO4 Deposited Coating Samples Exposed to Aggressive Environments at 550 °C and 800 °C for 200 h and 300 h.

Conclusion

This study investigated high-temperature degradation mechanisms across three industrial environments characterised by chlorine-dominated, sulphur-dominated, and mixed chemical conditions and evaluated the performance of twin-wire arc-sprayed Ni-based coatings under simulated laboratory conditions.

• Chlorine-rich conditions led to the formation of porous, non-protective oxide scales, while sulphur rich environments promoted sulphide formation and internal degradation. Mixed environments resulted in complex attack, including oxide breakdown and intergranular corrosion.

• TWAS coating performance varied significantly between the two systems, with CS-2 consistently outperforming CS-1 under all test conditions. Lifetime modelling confirmed lower material loss for CS-2, demonstrating its superior protective performance at both 550 °C and 800 °C.

• The results highlight the importance of coating composition and microstructure in controlling oxide stability and limiting the ingress of corrosive species. Crucially, a detailed understanding of the underlying degradation mechanisms provides a foundation for the rational design of improved coating materials with enhanced performance in aggressive environments.

Acknowledgements

Special thanks are extended to Dr Adnan Syed, Dr Luis Isern and
Prof John Nicholls from the Centre for Materials at Cranfield University for their technical support in interpreting case study data and corrosion mechanisms, as well as in the development of methodologies enabling coating trials under aggressive conditions. The author also acknowledges Dr Mario Cordero from Welding Alloys Group for his support in the design of new alloy chemistries, which demonstrated good resistance under laboratory conditions, and for his support with arc spray
coating deposition.

References

1. M Spiegel et al, “Fundamental aspects of chlorine induced corrosion in power plants,” Materials at High Temperatures, 2003, 20(2), pp. 153–159. https://doi.org/10.1179/mht.2003.018

2. K Khantisopon et al, “High-temperature corrosion investigations of deposit containing eutectic KCl-K2SO4 mixture on AISI 1015 and SS304 steels,” Corrosion Science, 2022, 205, pp. 110470. https://doi.org/10.1016/j.corsci.2022.110470

3. C orrosion Basics: Understanding the Basic Principles and Causes of Corrosion, Materials Performance, 2011, 50, pp.88.

4. S Floreen and R H Kane, “The sulfidation attack of a nickel-base alloy at intermediate temperatures,” Metallurgical Transactions, 1984, 15A, pp. 5-10.

5. E Sadeghimeresht et al, “Chlorine-induced high temperature corrosion of HVAF-sprayed Ni-based alumina and chromia forming coatings,” Corrosion Science, 2018, 132, pp. 170–184.
https://doi.org/10.1016/j.corsci.2017.12.033

6. A Usman et al, “Fireside corrosion behavior of thermally sprayed coatings for waste-to-energy power plant applications,” Journal of Materials Engineering and Performance, 2025, 34(19), pp. 22393–22405. https://doi.org/10.1007/s11665-025-11630-7

7. M Waeytens et al, “A microscopy study of nickel-based superalloys performance in Type I hot corrosion conditions,” Materials at High Temperatures, 2023, 40(4), pp. 272–282. https://doi.org/10.1080/09603409.2023.2188355

Dominic Marshall and Steven Slack, Corrous Industrial Group

Dominic Marshall, BA, MCMI, is Group Managing Director of Corrous Industrial Group, which delivers integrated protective coating, industrial cleaning, asset inspection and scaffolding services to heavy industries and regulated sites. Dominic specialises in bulk liquid storage and energy infrastructure and supports asset owners with specification development, estimating, project delivery and commercial control. His focus is on improving the reliability and repeatability of corrosion protection programmes through risk-based planning, robust QA and disciplined execution. He is an ICorr Level 2 Protective Coatings Inspector.

Steven Slack is Group Technical Director of Corrous Industrial Group, where he holds technical ownership of the group’s coating, lining and inspection delivery. Steven has extensive field and leadership experience in protective coatings, with specialist expertise in surface preparation, application control, inspection hold points and the delivery of complex tank lining projects. He supports clients and project teams with technical governance, troubleshooting, and the development of practical, fit-for-purpose specifications. He is an ICorr Level 3 Protective Coatings Inspector and an AMPP (formerly NACE) Senior Corrosion Technologist.

Introduction

Internal tank linings are widely used to protect steel and concrete assets from corrosion and chemical attack, extend service life, and reduce life-cycle costs. Despite this, premature lining breakdown remains common across industries including fuels, chemicals, water, wastewater and process storage.

While failure is sometimes attributed to ‘bad luck’, many breakdowns can be traced to recurring and identifiable weaknesses in specification, preparation, application control, commissioning, and operating discipline. The objective of this article is to summarise the ten most frequent causes of failure based on the authors’ practical field experience and to provide practical, engineering-led prevention measures that asset owners, specifiers, contractors, and inspectors can apply to significantly reduce risk.

Why Linings Fail: A Short Note on Mechanisms

Many lining defects present as blisters, pinholes, delamination, cracking, or rapid underfilm corrosion. These symptoms often have different root causes but are frequently linked by the same main underlying mechanisms:

• Cure inhibition or solvent entrapment caused by low
  temperatures, poor ventilation, excessive film build or incompatible overcoating windows.
• Incompatibility with internal cathodic protection (where fitted).
• Osmotic blistering where soluble contaminants (for example, chlorides or sulphates) draw water through the coating and form blisters.
• Permeation and chemical attack when a lining is not selected for the actual service conditions (including temperature and vapour phase exposure).
• Poor surface preparation and uneven weld profiles.
• Deterioration of the cleanliness standard between blasting and coating application.
• Underfilm corrosion driven by retained salts, moisture, or poor surface preparation that leaves active corrosion sites.

Photo: Lining Blisters

Photo 2: Showing Weld Defects, Substrate Contamination, Gingering on Tank Floor Plates.

Photo 3: Removal of the Lining and Preparation of the Steel Surface to ISO 8501-1 Sa2½.

Photo 4: Inspection of the Substrate Being Carried Out to Determine Soluble Salt Contamination (ISO 8502-6/9) and Surface Profile (ISO 8503).

Understanding these mechanisms helps teams focus on controllable parameters and hold points rather than treating defects as isolated events.

Additional Considerations for Specification and Risk Ownership

Beyond workmanship, the lining system is influenced by decisions made at the project design stage: specification, preparation philosophy, access and ventilation design, inspection scope, and commissioning constraints. High-performing projects treat lining installation as a managed engineering activity with defined acceptance criteria, rather than a “paint job” executed at the end of a shutdown.

A useful way to think about internal linings is to regard them as a barrier system with known limits. If the service environment, application conditions, or commissioning regime exceed those limits, failure becomes a matter of time rather than chance. The prevention measures that follow are therefore centred on controlling the few variables that matter most: service fit, cleanliness (including salts), environment, thickness, cure, and verification.

Two practical habits consistently separate reliable outcomes from repeat failures. Firstly, teams agree on the acceptance criteria before mobilisation — including where measurements will be taken, how many will be taken, and what constitutes a pass or fail. Secondly, they treat deviations as decisions, not inconveniences. If salt levels exceed the agreed threshold, the response is defined: re-clean, retest, and do not coat. If the dew point margin is not maintained, work stops. This clarity removes ‘’on-the-day’ debate and prevents schedule pressure from quietly overriding engineering controls.

Where possible, owners should also align lining work with a simple quality assurance risk register. For each major risk (contamination, condensation, over-build, incomplete cure, discontinuities), define the prevention control, the verification method, and the evidence required for sign-off. This approach makes lining projects easier to manage and far easier to defend when incidents, disputes, or warranty discussions arise.

Vapour Space Versus Immersion Exposure

A frequent source of surprise is vapour phase corrosion and attack. Condensation cycles, oxygen availability, and elevated temperatures can create a more aggressive environment in the vapour space than in the liquid phase. Where tanks store fuels, solvents, or chemicals with fluctuating levels, the splash zone and vapour space should be assessed explicitly. In some cases, a dual-system specification (or additional stripe coats / reinforcement in the vapour space) provides better reliability than a single uniform build.

It is also important to consider operational transients: hot fills, cold ambient periods, steam cleaning, or CIP chemicals. Lining selection should account for credible upset conditions, not only normal operation.

Acceptance Criteria and Measurement Methods

To reduce ambiguity, projects should define how compliance will be measured. Common controls include:

• • Environmental readings recorded at set intervals and whenever conditions change.
• Holiday testing with documented voltage, coverage, defect log, repair and re-testing.
• Soluble salt levels measured using the Bresle method (ISO 8502-6/9).
• Surface profile measured with replica tape or needle gauge.
• Wet film thickness (WFT) checks during application and dry film thickness (DFT) verification after cure.

While accurate and timeline reporting can be deprioritised by programme pressure, it ensures that issues are discovered early, while correction is still practical. It also provides auditable and defensible evidence to demonstrate compliance and protect the parties involved in the event of any future claim.

Typical Failure Signatures

Inspectors often encounter repeatable “signatures” that point to root cause:

• • Cracking, which can result from over-build, thermal cycling or substrate movement.
• Large blisters or broad delamination may indicate condensation, poor adhesion or incompatibility.
• Pinholes and rust spots are commonly linked to inadequate stripe coating, air entrapment or ineffective holiday testing.
• Small, high-density blisters often correlate with soluble salt contamination.
• A soft or easily damaged film suggests incomplete cure or incorrect mixing ratios.

Capturing these observations during inspection supports faster diagnosis and more targeted corrective action.

Prevention Measures

1. Incorrect Lining Selection for the Service Environment Selecting a lining based on price, familiarity, or generic data rather than on verified resistance to the specific stored product, contaminants, temperature range, and operating regime (including vapour space exposure) is a leading cause of premature failure.

Prevention Measures

• Assess both immersion and vapour phase exposure as the vapour space can be more aggressive than immersion.
• Confirm the stored media, concentration, operating temperature, cleaning chemicals, and any process upset conditions.
• Specify system build (primer/intermediate/topcoat), DFT range and cure requirements for the service.
• Use manufacturer chemical resistance data for the exact product and temperature, and verify it with independent guidance where appropriate.

2. Inadequate Surface Preparation (Profile, Cleanliness, and Degree of Preparation)

Even high-performance linings cannot compensate for inadequate surface preparation. Insufficient cleaning or an incorrect profile reduces adhesion and increases the likelihood of underfilm corrosion and delamination.

Prevention Measures

• Confirm that sharp edges are treated and that all weld spatter is removed.
• Ensure all critical areas receive a thorough stripe coat, ensuring sufficient coverage.
• Define the required preparation standard (e.g., Sa 2½ / SSPC-SP10) and the target profile range appropriate to the system.
• Hold point: do not proceed to coating until preparation has been verified and recorded.
• Inspect for shadows, tight corners, and complex welds that may need additional preparation.

3. Soluble Salt Contamination (Chlorides, Sulphates, Nitrates)

Soluble salts are a common hidden contributor to osmotic blistering and rapid underfilm corrosion. Salts can originate from stored product residues, marine environments, process contamination, or abrasive and water sources.

Prevention Measures

• Control abrasive quality and avoid the use of recycled abrasive that can introduce contaminants.
• Document test locations and results as part of the QA dossier.
• Include salt testing in the inspection plan (e.g., Bresle method) with acceptance criteria agreed pre-job.
• Use effective decontamination (fresh-water washing, steam cleaning, detergents) and re-test to confirm removal.

Poor Environmental Control During Application (Dew Point, Humidity, Temperature)

Applying linings outside specified environmental limits can cause condensation, amine blush, pinholing, poor cure, and reduced adhesion. Small excursions are often enough to create defects that only appear after commissioning.

Prevention Measures

• Maintain the specified surface temperature margin above the dew point (commonly >3°C, unless stated otherwise).
• Monitor steel temperature, air temperature, relative humidity, and the dew point throughout the shift.
• Stop work when limits are exceeded and resume only once conditions are stable and recorded. 
• Use dehumidification, heating, and forced ventilation where necessary — especially in enclosed tanks. This includes during overnight cure where required.

5. Incorrect Film Thickness (Under-Build or Over-Build)

Film thickness is a controlled parameter. Under-build reduces barrier performance, while over-build increases the risk of solvent entrapment, cracking, and cure issues — particularly in high build epoxies.

Prevention Measures

• Investigate and correct systematic thickness deviations rather than
  “averaging them out”.
• Specify minimum and maximum DFT per coat and for the total system; align with manufacturer guidance.
• Treat complex geometry as higher risk and plan additional stripe coats.
• Use WFT gauges during application and DFT measurements after cure; record results by area.

6. Poor Workmanship at Critical Details (Edges, Welds, Terminations, Nozzles)

Edges, welds, and terminations are stress concentrators and common initiation points for coating breakdown due to thin film build and mechanical damage.

Prevention Measures

• Inspect details at hold points before full coat application.
• Protect terminations and consider reinforcement where appropriate (e.g glass flake or fabric reinforcement).
• Specify edge grinding/radius requirements and stripe coats
  on all edges, welds and cut-outs.
• Use appropriate application methods to achieve target build on details (brush/roller stripe coats).

7. Inadequate Cure and Commissioning Control

Many failures are linked to lining systems being placed into service before they have achieved adequate cure. This is particularly prevalent in cold climates, under time pressure, or where ventilation is poor.

Prevention Measures

• Define cure criteria (time/temperature, hardness, solvent resistance) before the job starts.
• Do not introduce product, water, or cleaning chemicals until cure acceptance is formally signed off.
• Ensure ventilation is adequate to remove solvents and support cure, especially in deep tanks. 
• Verify cure using appropriate methods (e.g., solvent rub/MEK where applicable, hardness checks) in line with manufacturer guidance.

8. Holiday Testing Gaps and Ineffective Defect Repair

Pinholes and discontinuities allow rapid underfilm corrosion. Holiday testing is only effective when voltage selection, inspection coverage and repair methods are correct.

Prevention Measures

• Ensure testing covers welds, terminations, and complex areas where discontinuities are more likely.
• Include holiday testing as a formal hold point with correct equipment calibration and voltage selection.
• Maintain a defect log with locations, repair details, and re-test results.
• Mark defects clearly, repair in accordance with manufacturer guidance, and re-test repaired areas.

9. Inadequate QA/Inspection Hold Points and Documentation

It is essential that Quality Assurance (QA) hold points are enforced, otherwise defects are often ‘built in’ and only discovered late — when correction is costly or impractical.

Prevention Measures

• Define acceptance criteria for preparation, salts, environmental conditions, WFT/DFT, cure, and holiday testing.
• Ensure responsibilities are clear for all parties (asset owner, inspector, contractor) and records are retained.
• Implement a documented Inspection and Test Plan (ITP) with clear hold/witness points.
• Treat the QA dossier as part of the asset record, supporting future inspections and repairs.

10. Post-Handover Operational Factors (Mechanical Damage, Cleaning, Temperature Excursions and Water Bottoms)

Even a well-installed lining can fail early if operating conditions exceed design assumptions. Common issues include aggressive cleaning, unexpected chemical exposure, thermal cycling, prolonged water bottoms, and poor housekeeping leading to microbiological activity.

Prevention measures

• Document operating limits, cleaning restrictions, and compatible repair materials.
• Ensure repairs are compatible, controlled, and re-tested (including holiday testing).
• Monitor for water bottoms, sludge accumulation and microbial activity where relevant.
• Plan routine internal inspections and address minor defects early.

A Practical Vignette: Avoiding a “Perfect Storm” Failure

Consider a shutdown where the tank is cleaned and blasted late in the programme. The abrasive quality is acceptable, but soluble salts are not verified and environmental readings are taken only at the start of the shift. Overnight temperatures drop and the steel temperature approaches the dew point. The next morning, coating proceeds to maintain the schedule, resulting in intermittent condensation in shadowed areas. Film thickness is locally high on welds due to repeated stripe coats, and cure is assumed to be complete after a nominal time period.

The lining initially appears satisfactory, but blisters and rust spots develop within months of commissioning. In many cases, the root cause is not a single major error, but a chain of small misses: no salt verification, inadequate environmental control, over-build at edgework, and insufficient cure verification. Breaking any one link — for example, enforcing a hold point for salt testing or maintaining a strict dew point margin — can prevent the failure entirely. This illustrates why systematic hold points and evidence-based acceptance criteria are more reliable than relying on experience and good intentions alone.

Key lessons from this type of scenario are straightforward: establish measurable hold points early, keep environmental control equipment available and properly sized, avoid exceeding maximum film build on details, and verify cure with an agreed method rather than relying on time alone. When these controls are in place, the project team can move quickly with confidence — and when they are not, the apparent time saved is usually paid back many times over in rework and premature failure.

Asset Owner Risk Control

A lining should be treated as part of the wider asset management system — not as a one-off project. Owners can significantly reduce risk by ensuring that the specification is fit for purpose, enforcing hold points, and maintaining operational discipline after handover.

Practically, this means budgeting for the controls that prevent rework: time for decontamination and re-testing, provision for dehumidification and ventilation, access that allows proper inspection coverage, and a commissioning plan that does not force early immersion. The cost of these controls is typically small compared with the cost of early failure, product contamination, unplanned shutdowns, and repeat lining campaigns.

The Asset Owner’s Risk Management Checklist

• Correct lining selection for service (immersion and vapour)
• Surface preparation and salt control embedded in the ITP
• Environmental control during application (dew point margin maintained)
• Film thickness controlled within stated min/max limits
• Cure verification before exposure to service
• Defined hold points and documented QA dossier
• Holiday testing completed, defects repaired and re-tested
• Post-handover operating limits and cleaning restrictions documented
• Planned inspection intervals and compatible repair strategy.

Conclusions

Many internal lining failures are considered avoidable. When teams manage risk deliberately — by controlling preparation, contamination, environment, thickness, cure, and post-handover operation — service life becomes far more predictable and total cost of ownership reduces. Ultimately, the difference between a lining that lasts and one that fails early is rarely the coating brand. It is the discipline of specification, verification, and decision-making at hold points. If the project team can answer “yes” to the key questions — Is the system proven for service?
Is the steel clean (including salts)? Are conditions controlled?
Is the thickness within limits? Is cure verified? Is the lining continuous? — then failure risk drops dramatically. Where QA hold points are not enforced, defects are often “built in” and only discovered when it is too late.

References

1. ISO 8501-1, Preparation of steel substrates before application of paints and related products — Visual assessment of
surface cleanliness.

2. AMPP SP 10/NACE No. 2, Near-White Metal Blast Cleaning.

3. ISO 8502-6, Preparation of steel substrates before application of paints and related products — Tests for the assessment of surface cleanliness — Part 6: Extraction of soluble contaminants for analysis — Bresle method.

4. ISO 8502-9, Preparation of steel substrates before application of paints and related products — Tests for the assessment of surface cleanliness — Part 9: Field method for the conductometric determination of water-soluble salts.

5. ISO 8502-3, Preparation of steel substrates before application of paints and related products — Tests for the assessment of surface cleanliness — Part 3: Assessment of dust on steel surfaces prepared for painting (pressure-sensitive tape method).

6. AMPP SP0188, Discontinuity (Holiday) Testing of New Protective Coatings on Conductive Substrates.

7. ISO 8503, Preparation of steel substrates before application of paints and related products — Surface roughness characteristics of blast-cleaned steel substrates.

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

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