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External corrosion – the slow, silent assassin

17 June 2020

The anti-corrosion professional organisation, NACE International, estimated that external corrosion cost US process industries in excess of $1.7 billion in 2013.

Figure 1 – Pipe corrosion
Figure 1 – Pipe corrosion

(Click here to view article in digital edition)

It also calculated that North American organisations were spending a total of $260 million annually on coatings to prevent external corrosion. As a clear and present threat to most equipment in every process facility, external corrosion warrants closer analysis and prediction.

For internal corrosion, industry guidance and risk-based inspection standards use a combination of material type, environment (e.g. fluid, pressure, temperature) and corrosion protection measures to help asset integrity specialists decide which threats are credible. However, the technical support to competently analyse and predict external corrosion is rare.

Internal corrosion is seen as easier to quantify and predict but external issues and threats are just as common to almost all process equipment and pipelines. While the development of general external corrosion can often be slow, it can do much damage over a plant or pipeline’s lifetime (Figure 1).

It can be aggressive, especially along coastlines in hot climates when salt fogs wet steel surfaces in the morning. Water evaporation during the day drives up the salt concentration to cause high rates of corrosion and coating damage. Likewise, high external concentrations of sulphur oxide pollution greatly accelerate external corrosion by acidifying water and destabilising rust layers.

External corrosion can also be unexpectedly high, even in inland areas. After ‘the Great Storm’ of 1987 in the UK, a study in central London found that, due to salt transport from the sea into the city, the external corrosion rate was equivalent to that next of coastal locations. 

Figure 2 – CUI is a major threat to the integrity of facilities worldwide
Figure 2 – CUI is a major threat to the integrity of facilities worldwide

Combating CUI

Well-established risk-based inspection codes such as API 581 address general external corrosion attacks and corrosion under insulation (CUI). CUI is the external corrosion of pipework and vessels that occurs underneath externally clad/jacketed insulation due to water penetration. It tends to remain undetected as corroded areas are difficult to identify and conventional inspection methods are impeded by the insulation. Identified as a major threat to the integrity of oil and gas and petrochemical facilities worldwide, CUI damage can take the form of localized external corrosion in carbon and low-alloy steels, external stress corrosion cracking (ESCC) or pitting in austenitic and duplex stainless steel (Figure 2).

Insulation related corrosion is a major problem and has been responsible for a significant number of incidents and lost production time and is thought to account for 40-60% of pipework maintenance costs. Detailed guidance on CUI management is available in documents from the European Federation for Corrosion (EFC 55) and NACE International (RP0198).

The American Petroleum Institute (API) 581 standard also considers factors such as climate, condensation and how close equipment is to sources of potentially corrosive water mists, such as cooling towers. However, risk-based inspection schemes rarely include enough detail when specifying corrosion loops to pinpoint the areas of highest external corrosion risk. Current discrepancies also include the use of insufficient inspection methods, which can lead to undetected defects and the ultimate neglect of the whole asset. Others currently manage CUI risk by blindly replacing and renewing all insulation in a systematic manner, with limited upfront assessment of the scope required.

DNV GL has launched a new recommended practice (RP) designed to address the major safety threat and multi-billion-dollar cost posed by CUI. DNVGL-RP-G109 was developed in collaboration with major operators and the supply chain to deliver a practical and cost-effective recipe for managing its occurrence (Figure 3).

Figure 3 – DNVGL-RP-G109 was developed in collaboration with major operators and the supply chain
Figure 3 – DNVGL-RP-G109 was developed in collaboration with major operators and the supply chain

The RP is intended for use in the risk assessment of insulated static mechanical pressure systems, considering failures caused by loss of pressure envelope containment due to external CUI. The methodology is designed to be applied to process systems that operate at temperatures below 200°C and largely concentrates on the CUI of metallic materials, particularly carbon steel. 

Within the RP, DNV GL presents a systematic approach to CUI risk management, which includes the assessment, mitigation and updating of risk as well as continuous improvement. The approach is appropriate for both short and long-term time frames, taking into consideration related factors such as roles and responsibilities, reporting requirements and change management. Historic decisions made on individual assets also need to be aligned such as the material selection, coating condition and maintenance strategies.

Knowing the corrosive enemy inside and out

DNV GL’s failure analysis laboratory in Loughborough, UK has investigated major issues of external corrosion on flange faces, bolting and piping across various industries (Figure 4).

This has included instances where bolts have fractured due to loss of cross section and when flange corrosion was so severe that a fitness for service assessment was required. The key factors that were found to increase the risk of external corrosion were:

• Facility age – assets more than 20 years old had more extensive corrosion

Figure 4 – DNV GL laboratory in Loughborough
Figure 4 – DNV GL laboratory in Loughborough

• Coating inspection and maintenance – facilities with little or no coating management had severe external corrosion

• Water accumulation – areas where water can accumulate suffered enhanced attack. This included horizontally aligned flanges and items exposed to water run-off. In one case, a flat beam above a flange caused a mini waterfall whenever it rained and severe external attack occurred.

Corrosion under pipe supports (CUPS) for instance, is a particularly insidious form of corrosion that occurs at the pipe support to pipe interface (Figure 5). 

This can rapidly lead to serious piping damage, potentially resulting in pipe failure. Design features, such as using rubber spacers or poor draining supports, which can trap water and damage coatings, can accelerate it.

Improving inspection and maintenance

Asset integrity specialists continuously enhance their abilities to recognise what corrodes process facilities, how, and the rate of corrosion. It allows them to better optimise inspection and run mitigation programmes to maintain safe operations. Improving the scheduling of inspection and maintenance procedures helps to ensure that resources that could be used elsewhere in the business are not needlessly diverted to these activities.

Figure 5 – Corrosion under pipe support
Figure 5 – Corrosion under pipe support

This means finding new or improved ways to identify, measure and predict external degradation modes for each type of equipment. Factors such as climate, location, pollution levels, aerosol, salt transport measurements, airborne particulates, condensation, rain sheltering, and industry guidance are used together to assess the magnitude of the external corrosion threat. External corrosion appears simple at first glance, but its prediction can be just as complex as that for internal corrosion mechanisms.

The increasing volume of digital data and sophisticated analytical software available in process industries assists asset integrity specialists in this quest.

The trend for using 3D models for process assets facilitates external corrosion risk assessment of piping circuits as they provide improved details of the pipe configuration compared to paper drawings (Figure 6). For existing assets, laser scanning can be used to make up-to-date models of the pipe configurations. Eventually the 3D model, inspection data and real-time climate/environmental data will allow the creation of a digital twin of the asset. This will involve using analytics to predict external corrosion, plan inspections and direct coating maintenance activities to the areas at highest external corrosion risk.

For ease of implementation, an interactive digital tool, which combines the new CUI RP with live asset data, has been developed by the technical adviser to the oil and gas industry. DNV GL’s cloud-based ‘CUI Manager’ application will enable users to assess CUI risk and evaluate the risk impact of different mitigation measure, such as radiographic testing inspection, general visual inspection or close visual inspection after removal of insulation.

Mitigating external corrosion in process industries

The oil and gas industry, and others, coat and paint vessels and pipework as their main way to mitigate external corrosion attack. This can work well if the coating is carefully selected and qualified for site conditions. 

Figure 6 – Cloud-based ‘CUI Manager’ application enables users to assess CUI risk
Figure 6 – Cloud-based ‘CUI Manager’ application enables users to assess CUI risk

However, there have been failures (Figure 7). For example, when a coating against atmospheric corrosion is used on cool pipework, this can potentially result in heavy condensation occurring from a humid atmosphere. In this case, an immersion-grade coating would be required. 

DNV GL’s coating test facilities qualify coating systems for many operators including equipment to simulate conditions worldwide, as well as examining the effects of pollutants.

Coating laboratories are equipped with advanced environmental simulation chambers that allow coatings to be exposed to humidity and temperature cycling as well as ultra-violet light and simulation of pollutant gases. This enables experts to test coating performance in environments ranging from rainforests to deserts. One recent project examined the performance of products applied as a single coat compared to the operators specified three-coat systems. It was found that a single-coat system would greatly reduce the time needed for maintenance painting and for many environments, provide adequate protection.

Standards and guidelines

Coating systems need regular inspection to evaluate their condition and detect any evidence of the early stages of corrosion. Many operators have internal standards for assessing the severity of corrosion and coating degradation. International standards such as ISO 4628, ASTM D5065 and D610 can also be applied.

Figure 7 – External corrosion and coating damage
Figure 7 – External corrosion and coating damage

All these standards involve comparing coated surfaces to a library of pictures showing coatings and steel substrates with varying levels of damage to assess the degrees of coating degradation and substrate surface rusting. They do not however, address the depth of attack under rust layers.

The chief issue with this approach is the subjective nature of the judgements, which often depends on the experience of the inspection personnel. To ensure a consistent approach, trained assessors are used in Loughborough’s materials laboratory to conduct site surveys for external corrosion, CUI and CUPS. A recent survey of a process facility looked at more than 2,000 locations and found 2% required urgent attention and 10% needed more frequent inspection.

Improving external corrosion management

The oil and gas and process industries continue to improve the management of internal corrosion by investing heavily to develop continuous corrosion monitoring, predictive tools and data management software. 

As industry adopts these and similar tools more widely, the control of external corrosion attack will be much improved and the risks better controlled.

About the author:

Dr. Tim Illson is Principal Specialist with DNV GL – Oil & Gas and has worked in industrial corrosion control for more than 30 years and is presently involved in consultancy for a wide range of oil and gas, transport, processing and production activities. Consultancy roles performed include corrosion management planning, corrosion engineering, production chemistry and flow assurance. Specific areas of technical expertise include hydrogen compatibility, selection and application of corrosion monitoring techniques together with their interaction with inspection, materials selection for oil and gas processing plants, and risk-based life cycle costing and economic analysis.

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