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

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

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

1. Introduction

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

Their auxiliary components, however, often operate under

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

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

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

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

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

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

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

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

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

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

2.2 Moisture Retention and Corrosive Exposure

The vent pipe interior is subject to:

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

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

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

3. Component Description and Service Conditions

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

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

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

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

4. Observations and Corrosion Morphology

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

Figure 1: General Oxidation in Non-Fouled Areas.

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

Figure 2: Barnacle Colonisation and Calcareous Deposits.

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

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

6.3 Crevice Corrosion

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

6.4 Microbiologically Influenced Corrosion (MIC)

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

produces iron sulfide films, contributing to aggressive localised attack.

6.5 Biofouling-Assisted Corrosion)

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

7. Discussion of Interacting Environmental Factors

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

Three primary stages of degradation were identified:

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

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

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

8. Summary Assessment

 The combined evidence supports the following deterioration mechanisms:

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

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

9. Engineering Recommendations

 9.1 Material Upgrade

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

9.2 Internal Protective Coatings

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

9.3 Drainage Enhancement

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

9.4 Improved Filtration

Upgrade seawater filtration to prevent larvae and particulate ingress.

9.5 Biocide Control

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

9.6 Routine Access and Inspection

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

10. Conclusion

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

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

References

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

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

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

Author Experience Statement – Contactless Magnetic Inspection Technology (CMIT)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Strengths of CMIT in Defect Detection

Corrosion Metal Loss Detection

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

Crack and Stress Corrosion Cracking (SCC) Detection

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

Mechanical Threat Identification

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

Geohazard Interaction Monitoring

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

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

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

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

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

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

Integrated Pipeline Integrity Approach with CMIT

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

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

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

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

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

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

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

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

Figure 7 (b): Direct Examination photos

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

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

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

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

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

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

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

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

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

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

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

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

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

Case Study Outcomes

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

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

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

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

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

Conclusions

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

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

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

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

References

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

Meet The Author

Neil M Cowin, MSc, CEng

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

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

Introduction

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

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

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

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

Methodology Outlining the Status of Subsea NDE and Further Requirements

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

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

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

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

Pulsed Eddy Current (PEC)

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

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

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

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

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

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

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

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

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

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

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

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

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

Acoustic Resonance – Subsea Operability

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

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

CT – Scanning or Computed Tomography by Radiation Scanning Data.

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

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

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

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

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

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

Corrosion Types and Threats in Coated Pipelines

Coating Types

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

Corrosion Threats

Exacerbation by CO2, H2S, and chloride salts.

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

Integrity Risks

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

Inspection History

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

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

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

Prioritisation

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

Available NDE Techniques

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

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

General Guidance and API Standards

Recommended guidance includes:

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

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

Way Forwards

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

Discussion

Some key outcomes in these processes to date have been:

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

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

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

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

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

Figure 7: Project Consideration’s

Conclusions

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

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

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

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

Future Needs

Industry requirements continue to develop at a rapid pace.

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

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

References

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

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

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

Introduction

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

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

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

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

Corrosivity of Bridge Environment

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

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

Challenges and Costs

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

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

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

Photo: Distance Harness Assisted Solvent Wash Under Deck.

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

Maintenance Painting Process and Access

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

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

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

Photo: MEWP (Mobile Elevating Working Platform).

Selective Corrosion Repair Sites

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

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

Photo: Bridge Hangar Painting.

Geography and Geometry

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

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

Photo: Metal Coating Using A Trug.

RAT work necessitates:

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

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

Deck/Road Level – Traffic Issues

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

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

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

Below Deck

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

Photo: RAT Based Pressure Cleaning Activities.

Preparation and Painting Specifications

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

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

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

Photo: Incline Cable Painting.

Paint Lifetime Expectancy

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

References

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

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

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

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

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

Meet the Author

Dr Raghu Srinivasan is an Associate Professor and Chair of the Mechanical Engineering Department and Director of the Environmental Degradation Laboratory (EDL) at the University of Alaska Anchorage (UAA). He received his MS and PhD degrees in mechanical engineering at the University of Hawaii at Manoa in 2005 and 2010, respectively. Dr Srinivasan’s research focuses on atmospheric and marine corrosion, materials compatibility, and corrosion in oil and gas infrastructure, with a strong emphasis on Arctic and sub-Arctic environments. He currently serves as the Chair of the Research Society Leadership Council (RSLC, 2025–2027) and served as Vice-Chair of the Research Programme Committee (RPC, 2023–2025) for the Association for Materials Protection and Performance (AMPP). He has been recognised with multiple awards: UAA’s Chancellor Award for Research, the NACE Foundation Book Scholarship Award, the Harvey Herro Best Poster Award, the Materials Performance Corrosion Innovation of the Year Awards (2019 and 2023), and the NACE International Research Seed Grant (2019).

Introduction

Atmospheric corrosion is a complex process, which involves chemical, electrochemical, and physical changes to the metal exposed. Atmospheric corrosion occurs when a metal surface is under a thin layer of moisture, but not completely immersed, and the metal surface corrodes while exposed to environmental factors. The atmospheric corrosion damage in cold environments is close to the main human activity, which is concentrated near the coastal areas.

The substantial human growth and climate change in the Arctic and sub-Arctic region push for a renewed, better understanding of the atmospheric corrosion mechanisms that can lead to a good choice of materials selection and better design practices for infrastructure and other applications. This article describes the development of multi-angle corrosion test racks that were deployed at four test sites across Alaska, each distinct in their environment and equipped with weather sensors and chloride candles.

Atmospheric Corrosion in Cold Climates

The Arctic and sub-Arctic region identified by the U.S. Army Cold Regions Research and Engineering Laboratory (CRREL) [1] has an average temperature of -18°C or less during winter. The most common assumption is that there is very little to no corrosion in cold environments [2]. However, previous studies in the Antarctic and Arctic regions have disproved that notion, finding that corrosion rates are substantial [3-5]. The atmospheric corrosion damage in cold environments is close to the main human activity, which is concentrated near the coastal areas. Previous studies in the sub-arctic region of Canada, Norway, and Russia show extensive atmospheric corrosion rates (when compared to Antarctica) due to human developments and the resulting increase in mining and metallurgical industries [2]. Experimental and theoretical work has shown that the electrochemical process proceeds at temperatures as low as -25°C to -20°C [6-7].

Sereda measured the potential between platinum and zinc electrodes at -20°C, concluding that when an electrolyte is present, corrosion will proceed [6]. Moreover, very little corrosion data is available for metal alloys exposed to cold conditions. Studies by Divine and Perrigo [5] in Anchorage, Alaska; Biefer [8] in the

Canadian Arctic and sub-Arctic sites; Kucera et al. [9] in Scandinavia; and Mikhailov et al. [10] in eastern Siberia have shown corrosion rates of carbon steel close to the C1 category of the ISO 9223 classification (Table 1).

Table 1: One-Year Corrosion Rates and Corrosion Categories.

Even though the corrosion rates are lower than the C1 category, the substantial human growth and climate change in the Arctic and sub-Arctic region push that envelope. Because of this, there is a case to add a cold climate category to the classification. Factors that drive the atmospheric corrosion in cold climates are winds that can bring in salt-laden snow from the marine environment, and the use of de-icing salts can also contribute to high levels of chlorides [2]. The eutectic point, or the freezing point, of de-icing salts can be lowered to -50°C, melting the ice/snow layer on top of metal samples [7]. This phenomenon keeps metal samples moist for much longer periods, thus increasing the time of wetting (TOW).

In the presence of chlorides and moisture, extensive atmospheric corrosion damage can be observed on metal samples. Another contributing factor to high corrosion rates is low rainfall, which in turn cannot periodically wash off the deposited chlorides and SO2 on top of the samples [2]. In addition, ever-increasing ambient temperatures due to climate change in recent years affect the snow presence on top of the metal samples [11]. The temperature of the samples is not too high to evaporate the deposited snow/ice but high enough to cause melting and sustain moisture for longer periods of time. This leads to the formation of varying thicknesses of wet ice/snow layers on the metal surface. Long hours of sunlight in the summer also increase the surface temperature of metal samples beyond the ambient temperatures, causing dew formation and condensation, which in turn results in higher TOW.

Multi-Angle Test Rack Design

The design and methodology of atmospheric corrosion test racks have been guided by several pivotal standards over the years.

Prominently, the ASTM standard G50: “Standard Practice for Conducting Atmospheric Corrosion Tests on Metals,” and more particularly subsection five concerning exposure racks and frames, has served as an instrumental reference point for this research herein [12]. Similarly, ISO 8565, “Metals and alloys—Atmospheric corrosion testing—General requirements for field tests,” was another crucial standard consulted during the design process [13]. Over time, atmospheric corrosion test racks have seen iterative developments to address specific research requirements. Notable research endeavors that have trod a similar path include studies conducted in diverse geographies.These studies offer a comparative perspective and serve as benchmarks for the current investigation. A seminal study from 1995 introduced an atmospheric test rack design that facilitated specimen exposure across various orientations and angles [14].

Subsequently, a research team from the University of Hawaii devised the “Compact Octagonal-Prism Portable Exposure Rack” (COP-PER) to specifically assess the impact of wind direction and specimen orientation on corrosion rates [15]. Additionally, collaborative efforts from Spain and Portugal resulted in the development of a tree-shaped rack, designed to concurrently evaluate specimen orientation and exposure angle in atmospheric corrosion studies [16].

Traditional test racks used for atmospheric corrosion monitoring are often inadequate for Arctic deployment. They cannot withstand snow loads, high winds, or severe temperature swings. To address this, a modular and adjustable atmospheric corrosion test rack was designed, later patented in the United States as US 11,499,909 B2. The rack design includes adjustable exposure angles (0°, 30°, 45°), a modular aluminum frame, integrated sensors, and corrosion-resistant construction (Figure 1).

Figure 1: Adjustable Multi-Angle Corrosion Test Rack.

Atmospheric corrosion standards recommend an exposure angle of 30 degrees from the horizontal, facing south, and the lowest specimens be at least 30 inches above the ground. Time of wetness is one of the main parameters for atmospheric corrosion testing and can vary drastically depending on the angle of the exposed surface. This modular and adjustable corrosion test rack allows us to change the direction of exposure (north, south, east, or west) and the angle of exposure (0, 30, or 45 degrees to horizontal). These changes can be made easily and will save time when future adjustments are required for different exposure angles and directions. Lastly, this design can support a full weather monitoring system (Figure 2). These parameters include, but are not limited to, relative humidity (RH), ambient air temperature, TOW, rainfall, wind velocity, UV radiation, barometric pressure, and aerosol chloride and sulfate deposition.

Figure 2: Multi-Angle Corrosion Rack with Auxiliary Weather Station.

Establishing Test Sites

Four strategic locations were selected as preliminary testing sites, with site selection and characterization heavily influenced by ASTM G92 “Standard Practice for Characterisation of Atmospheric Test Sites” [17]. Their positions can be referenced in Figure 3, which provides a map of Alaska.

Figure 3: Map of Alaska Showing Four Corrosion Monitoring Sites.

Kodiak, AK – Pacific Spaceport Complex (PSCA) – Aggressive Marine Environment

Kodiak, AK, represents the aggressive marine environments commonly found along the southern and southeastern coastlines of Alaska. Coastal cities, such as Kodiak, receive on average a steady coastal breeze averaging 9 knots (4.6 m/s), average yearly precipitation of 65 inches (1651 mm), and average ambient temperatures of 41°F (5°C). This creates an aggressively corrosive

environment with relatively steady electrolyte exposure from rainfall and high relative humidity levels, as well as steady prevailing winds that provide high deposition rates of aerosol-borne Cl.

During the summer months, Kodiak experiences a maximum daily sunlight period of approximately 16 hours at the summer solstice and a minimum of 6.5 hours at the winter solstice. Both the summer and winter solstice are indicative of the maximum and minimum number of sunlight hours, respectively. This provides for periods of consistent solar irradiance exposure, which are maximized during the summers in Alaska. The exact exposure site is located in close proximity to the Pacific Spaceport Complex on Kodiak Island. Using pre-existing structures places the exposure rack ~5-6 feet elevated from the ground level and ~600 feet from the open ocean water.

Anchorage, AK – University of Alaska Anchorage (UAA) – Mild Marine Environment

Of the two exposure sites operated in Anchorage, AK, one resides at the University of Alaska Anchorage (UAA) and represents a very mild marine environment. Positioned 25 miles farther north than Kodiak, this site presents colder average temperatures and lower average precipitation rates comparatively. The average ambient temperature in Anchorage is 39°F (3.9°C) with an average precipitation of 16.9 in (430 mm). Both Anchorage sites typically exhibit lower average levels of relative humidity and receive lower Cl- deposition rates than those of Kodiak, but still experience these coastal effects, being only slightly offset from the shoreline.Anchorage sites receive longer periods of daily sunlight exposure, reaching upwards of 18.5 hours at the summer solstice and lowering to 5.5 hours at the winter solstice. This again provides generous solar irradiance exposure that is maximized during the summer months. At UAA, the particular exposure site is positioned on a building roof and is therefore elevated above the ground floor by ~30-45 feet. The site is also positioned much farther from the shoreline of the neighboring head of both the Knik and Turnagain Arm by ~4 miles. Where Kodiak is positioned far from any industrial or urban environment, UAA is positioned only a couple of miles from the downtown center. UAA is therefore more apt to be influenced by associated factors with urban areas, such as vehicle emissions and combustion byproducts, among others.

Anchorage, AK – Port of Alaska (POA) – Moderate Marine Environment/Mild Industrial Environment

The second of the two exposure sites, which operates in Anchorage, AK, resides at the Port of Alaska (POA, or “The Port”) and represents two environmental types with varying positions. Being situated similarly to the UAA site, all of the previous meteorological averages and data also apply to this site. The Port of Alaska handles the majority of fuel and freight cargo in Alaska, and it is an understatement that it is the lifeline of the Alaskan people. Its proximity to the ocean and constant truck movements make the Port of Alaska a strategic location to collect atmospheric corrosion data. In summary, upon inspection, the site presents a less corrosive environment than Kodiak does, with ample summer time solar irradiance exposure.

Fairbanks, AK – University of Alaska Fairbanks (UAF) – Inland Urban Environment

The last site is operated in Fairbanks, AK, at the University of Alaska Fairbanks (UAF), which best represents an inland urban environment. The summers are warmer than both Anchorage and Kodiak, with an average temperature of 60°F (15.6°C). However, the winters are much colder, with average winter temperatures of -4.3°F (-20°C). Average annual precipitation levels are the lowest of the four sites at 12.4 in (~315 mm). Fairbanks, being situated in a more northern location than Anchorage, receives exceptionally long periods of sunlight during the summer months, exceeding 21 hours at the summer solstice.

During winters, the inverse occurs with a mere 4 hours of sunlight at the winter solstice. This provides an incredibly large amount of solar irradiance exposure during the summer months relative to the other sites. Due to Alaska’s sheer size, Fairbanks lies approximately three hundred miles (~500 km) away from the nearest coastal area, which provides quite radical and unique weather challenges during the winter months. The particular site lies atop the Usibelli Engineering Building at approximately four stories, thus elevating the exposure rack ~60–72 feet above the ground floor.

While the exposure to airborne Cl- and SO4²- is expected to be considerably lower than at 28 Kodiak due to the relative positioning from open bodies of salt water, respectively, the UAF exposure site does typically experience an elevated exposure to airborne SO4²-. Interior Alaska is abundant in individual residential heating solutions for the winter months. The most common combustion sources include heating oil and wood. Both produce either primary or secondary SO4²- within the atmosphere, with primary SO4²- generally making up the most significant percentages. Fairbanks’ geographical characteristics are also highly conducive to frequent temperature inversions during winter. Temperature inversions most often cause cold air masses to settle beneath larger warm air masses. In effect, this traps any and all airborne contaminants within the lower-lying cold air masses. Trapped contaminants then have a longer period and a chance to deposit on the sample surfaces. Additionally, UAF also sits across the street from the University Power Plant. Table 2 gives a detailed layout of each test location and geographical coordinates.

Table 2: Test Sites’ Coordinates, Distance From Sea, and Elevation.

Some Notable Results and Trends

Figure 4 delineates the ambient air temperature at the PSCA site, which, during the winter months, dips below the freezing mark on several instances and occasionally falls beneath -5°C. Despite these sporadic plunges, the overall trend captured by the solid red line indicates that the ambient air temperature stays above 0°C throughout the entire year-long exposure period, with the mean average, illustrated by the dotted red line, stabilising around 6°C. The PSCA’s proximity to the Pacific Ocean, a mere 600 feet away, confers a stabilising effect on its air temperature, moderating the extremes that might otherwise be observed. The climatic profile of Fairbanks, Alaska, is characterised by its starkly contrasting temperatures, with intense cold in the winter and, unexpectedly, notable warmth in the summer. As depicted in Figure 5, the ambient air temperature at the UAF site plummets to a frigid -35°C in December 2022 and soars to 28°C by late June 2022.

Figure 4: Ambient Air Temperature at PSCA – Raw vs Averaged Data. Figure 5: Ambient Air Temperature at Fairbanks – Raw vs Averaged Data.

Table 3 shows the calculated chloride and sulfate deposition rates for each test site over each exposure. The PSCA site has four to seven times the amount of chlorides when compared to UAF and UAA, the PAA test sites. Figure 6 depicts the corrosion rates for 1008 carbon steel (UNS G10080) for a 12-month exposure period. The carbon steel samples at the PSCA site exhibited corrosion rates at least four times greater than the carbon steel samples exposed at UAF, PAA, and UAA.

This can be attributed to the weather data, where PSCA recorded at least four times the amount of chloride deposition, and the samples spent at least 18% more time wet through all sites and exposures. At the PSCA site, a distinct correlation was observed between the exposure angle and corrosion rate. Samples exposed at 0° showed the highest corrosion rates, followed by those at 30°, with the lowest rates seen at 45°. The TOW data indicates that the 0° angle samples remained wet for longer periods compared to 30° and 45°. Although the other sites – UAF, PAA, and UAA – exhibited less pronounced trends and experienced four times less corrosion than PSCA, the samples at 0° consistently showed higher corrosion rates than those at 30° and 45°.

Table 3: Chloride and Sulfate Deposition Rates.

 Figure 6: Average Corrosion Rates of 1008 Carbon Steel Over Full 12-Month Exposure Period.

Corrosion Rate Conversion

The following table is useful to put the above corrosion rates into context for the four test regions above.

Table 4: Corrosion Rate Conversion. 

Conclusion

New and innovative multi-angle corrosion test racks, each with auxiliary weather stations, were established at four test sites spanning across Alaska, USA. Each of Alaska’s four test sites presents a distinct corrosion profile: Kodiak (PSCA) exhibits high chloride-driven corrosion, Anchorage (PAA/UAA) faces freeze-thaw cycles with de-icing salts, and Fairbanks (UAF) experiences frost-dew cycling. Initial field campaigns revealed a clear correlation between exposure angle and corrosion rate. The combination of urbanisation and proximity to marine environments makes Arctic and sub-Arctic regions in North America, particularly Alaska, an important natural laboratory to study atmospheric corrosion in cold regions and the development of predictive models and corrosivity maps tailored for Arctic conditions. The fundamental knowledge of studying the basic atmospheric corrosion mechanisms in extreme cold conditions will result in better design practices for the built environment in the changing Arctic.

Acknowledgements

The author acknowledges the UAA’s College of Engineering and ConocoPhillips Arctic Science and Engineering Endowment, NASA EPSCoR CAN grant, and the many undergraduate students and collaborators who contributed to the design, installation, and operation of the corrosion monitoring sites across Alaska. Special thanks to graduate students Mr Tyler Cushman, Mr Jozef Huner, Mr Lawrence Giron Jr., Mr. Jacob Bodolosky, and machinist Mr Corbin Rowe. The author also gratefully acknowledges the organizations that provided access and site space for test rack installation, including the Pacific Spaceport Complex–Alaska (Kodiak), the Port of Alaska, the University of Alaska Anchorage, and the University of Alaska Fairbanks.

References

1. E A Wright, CRREL’s First 25 Years: 1961–1986, US Army Cold Regions Research and Engineering Laboratory, Hanover, NH, 1986.
2. Revie Winston (2000) Uhlig Corrosion Handbook, 2nd Edition.New York: John Wiley & Sons, Inc
3. ASTM Committee G1 “Corrosiveness of Various Atmospheric Test Sites as Measured by Specimens of Steel and Zinc,”in Metal Corrosion in the Atmosphere, ASTM STP 435, American Society for Testing and Materials, Philadelphia, PA, 1968, 360–391.
4. A Pearce and C G Smith, The Hutchinson World Weather Guide, Hutchinson, London, 1984.
5. J R Divine and L D Perrigo, “Atmospheric corrosion testing in the arcticand subarctic—a review,” Paper No. 389, in Proceedings of the Corrosion 86 Conference, NACE, Houston, TX, 1986.
6. P Sereda, “Weather Factors Affecting Corrosion of Metals,” in Corrosion in Natural Environments. ASTMSTP 558, American Society for Testing and Materials, Philadelphia, PA, 1974, pp. 7–22.
7. G W Brass, “Freezing depression by common salts: implications for corrosion in cold climates,” in Proceedings of the National Association of Corrosion Engineers, Canadian Region Western Conference, Anchorage, Alaska, 1996, pp. 447–453.
8. G A Biefer, Perform., 20(1), 16 (Jan. 1981).
9. V Kucera et , “Corrosion of Steel and Zinc in Scandinavia with Respect to the Classification of the Corrosivity of Atmospheres,” in S.W. Dean and S. Lee (Eds.), Degradation of Metals in the Atmosphere, ASTM STP 965, American Society for Testing and Materials, Philadelphia, PA, 1988, pp. 264–281.
10. A Mikhailov, M Syloeva, and E Vasilieva, Data Base on Atmospheric Corrosivity in Towns and Industrial Centres in the Territory of the Former USSR, Institute of Physics and Chemistry, Russian Academy of Science, Moscow,
11. A A Mikhailov, P V Strekalov, and Yu M Panchenko, “Atmospheric corrosion of metals in regions of cold and extremely cold climate (a review)”, Protection of Metals, 2008.
12. ASTM G50, “Standard Practice for Conducting Atmospheric Corrosion Tests on Metals,” ASTM International, doi: 10.1520/G0050-20.
13. ISO 8565, “Metals and Alloys. Atmospheric Corrosion Testing. General Requirements,” BSI Standards Limited, 2011.
14. Coburn, M Komp, and S. Lore, “Atmospheric Corrosion Rates of Weathering Steels at Test Sites in the Eastern United States — Effect of Environment and Test-Panel Orientation,” in Atmospheric Corrosion, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959: ASTM International, 1995, pp. 101-101–13.
15. L H Hihara, J Kealoha, and N Das, “Studying the effect of wind direction and specimen orientation on the corrosion of 1018 steel using a compact octagonal prism portable exposure rack,” NACE, 2019.
16. J J Santana, et , “The influence of test-panel orientation and exposure angle on the corrosion rate of carbon steel. mathematical modelling,” Metals (Basel), vol. 10, no. 2, p. 196, Jan. 2020.
17. ASTM G92, “Standard Practice for Characterisation of Atmospheric Test Sites,” ASTM International, 2020.