ISO 12944 – The Corrosive Environment

ISO 12944 – The Corrosive Environment

Categorising corrosivity by type of environment

In a recent article, we introduced you to ISO 12944, the internationally recognised standard that provides the guidelines for the use of paint and coatings to protect assets from corrosion. The second part of the standard discusses the corrosive environment. This article introduces you to this part of ISO 12944 and the changes that were introduced in the latest revision in 2018.

What is the corrosive environment?

The corrosive environment describes the environment in which the asset to be protected is situated. There are many variables within corrosive environments. Combined, these determine how corrosive the environment is, and therefore the types of protective paint systems that are needed to help prevent corrosion (covered in part 5 of the standard).

When discussing the corrosive environment, two terms are used:

  • The local environment, which describes the atmospheric conditions around a particular component
  • The micro-environment, which is the environment at the interface between an element of a structure and the local environment

The environmental factors that determine an environment’s corrosivity are:

  • Climate (the weather, which is established by reference to historical data)
  • Atmosphere (the gases – including aerosols and particles – that surround the asset to be protected against corrosion)

The classification of environments considers temperature, relative humidity, and the time of wetness (the length of time that the metal surface is likely to be covered in a film of electrolyte that can cause atmospheric corrosion). In brief, atmospheric corrosivity calculations are made by summing the hours when the relative humidity is above 80% and the temperature is above 0°C.

Corrosivity is dependent on the corrosive agents present in the environment, especially gases such as sulphur dioxide, and salts such as chlorides and sulphates.

Types of corrosive atmospheres

When specifying the protective coatings that should be used on assets, ISO 12944 considers the type of atmosphere in which the asset is located, and categorises these from rural (away from corrosive agents such as sulphur dioxide) through to marine (where airborne salts are present).

If the asset is indoors, the potential for corrosion is usually lower because atmospheric pollutants are usually reduced. However, if the indoor asset is poorly ventilated or suffers from high humidity, then this increases the potential for condensation and, therefore, corrosion.

The categories of corrosivity are taken from a separate standard, ISO 9223;2012 – “Corrosion of metals and alloys — Corrosivity of atmospheres — Classification, determination and estimation”.

The scientific method for determining corrosion rate is determined by calculating the rate of metal loss on sample coupons (mild steel or galvanized steel) that are placed in the given environment. In practice, this is rarely performed for the determination of corrosivity for a paint specification. The corrosivity is determined by an objective estimation of the general description of the environment based on the descriptions in the standard, and the professional assessment by all parties involved in drawing up the corrosion protection specification.

Location of asset and corrosivity

When protecting assets from corrosion, ISO 12944 also considers whether the asset is in soil or water. Where assets are only partially buried in soil or partly immersed in water, the corrosion is usually localised to where the rate of corrosion can be highest.

Corrosion of assets that are immersed in water depends upon the type of water (fresh, brackish, or salt), how much oxygen is present in the water, the water’s temperature, and the substances that are dissolved in the water. There are three different ‘zones’ for corrosion, transitioning from the splash zone (wetted by spray), through intermediate (where wetting is fluctuating), to fully immersed.

Corrosion of those assets that are buried in soil depends on factors that include the minerals present in the soil and its water and oxygen content. The type of protection coating needed for buried-in-soil assets may differ along the length of the asset, because it is more likely that they will be buried in different soils – in such cases, the rate and severity of corrosion will differ.

Changes to ISO 12944 in 2018

There are three major changes in environmental categorisation as described in ISO 12944. There are now five environmental categories for onshore assets, ranging from C1 (very low corrosivity, typically in a climate-controlled indoor environment) to C5 (very high corrosivity environments, such as a coastal refinery).

A new environmental category has been introduced – the CX category, which covers offshore environments. This category is now covered in detail in a new section of the standard – part 9.

The IM categories, covering immersed assets, now include a new category (IM4) that deals with immersed assets with cathodic protection.

Key takeaways

In summary, the environment in which an asset is sited has a significant effect on the potential for it to corrode, and therefore the design of corrosion prevention system used. Factors that determine corrosivity of the environment include temperature, humidity, condensation, and corrosive pollutants in the atmosphere.

In classifying corrosion environments, ISO provides a reliable guide for the design, implementation and maintenance of structures and corrosion prevention systems and the applicable characteristics of paints and coatings that may be used.

In our next article in this series covering ISO 12944, we examine the section of the standard that deals with steel structure design. In the meantime, to learn about the Institute of Corrosion Coating and Inspection Training Courses – presented by IMechE Argyll Ruane and Corrodere – contact us today.

Corrosion Protection – A Week of Webinars

Corrosion Protection – A Week of Webinars

Bringing the corrosion conversation to you

After the huge success of the week of webinars to combat corrosion, the Marine Corrosion Forum and the Institute of Corrosion are collaborating once more to bring five more exceptional webinars into your homes and places of work, as we discuss some of today’s corrosion protection issues.

These webinars, presented by some of the world’s leading corrosion experts, will follow the same format as before: one each day for five days, each presented at a time to allow as many people as possible to attend. You’ll need to be quick to register, though – there is a limit of 200 people for each webinar, and places will be allotted on a first-come-first-served basis.

Online delegates to this series of webinars are in for a real treat – with a big focus on offshore wind and other renewables, and a ‘dip-in/dip-out’ timetable that allows you to attend the webinars individually without needing to commit to attending all five. Oh, and registration for these corrosion protection webinars is free.

Before a summary of each webinar, let’s introduce the presenters – it’s quite a line-up.

Roger Francis corrosion expertDr Roger Francis

Dr Roger Francis is one of the UK’s leading experts in corrosion-resistant alloys – both stainless steels and copper-based. Director at RF Materials, Dr Francis won’t mind us telling you that he has amassed four decades (and counting) of experience in areas that include marine, oil and gas, chemical and process, power, desalination, and mining. He has authored six books, and edited several more, as well as publishing over 80 technical papers. His consultancy work includes failure analysis, materials advice, and training in various aspects of corrosion. A founder member of the Marine Corrosion Forum and a Fellow of the Institute of Corrosion, Roger never fails to deliver an informative and enjoyable paper.

Dr Adnan Syed corrosion expertDr Adnan Syed

With a PhD in Energy Materials, Dr Adnan Syed is currently a Research Fellow at Cranfield University. There, he is involved in the field of high-temperature material degradation and investigating the effects of environment on the static and stress corrosion life of alloys used for gas turbine blades. This includes the use of thermodynamic software for better understanding of the corrosion mechanisms and advanced microscopy techniques for the alloy’s microstructure details. His PhD title was ‘Fireside corrosion study of superheater materials in advanced power plants’. Dr Syed’s extensive career experience, includes working for organisations to provide chemical solutions to R&D and technical teams via Failure Mode Effects & Analysis (FMEA) toward the development of products and processes.

Lars Lichtenstein corrosion expertLars Lichtenstein

You couldn’t wish for a more accomplished corrosion mitigation voice from the world of renewables, especially offshore wind. Lars Lichtenstein is the lead principal specialist within Renewables Certification for corrosion protection issues at DNV GL – the responsible expert for the DNVGL-RP-0416 corrosion protection for wind turbines. Extremely influential in setting and interpreting DNVGL codes and rules in this sector, you’ll discover that Lars is also an extremely competent and accomplished presenter.

 

Brian Wyatt corrosion expertBrian Wyatt

Just when you thought it would be impossible to add to the expertise of our presenters, we bring you Brian Wyatt. Members of the Institute of Corrosion will recognise Brian as a past president of ICorr and Director at Corrosion Control Limited. An acknowledged expert in cathodic protection, Brian has been heavily involved in transferring best practice from the oil and gas sector to the offshore wind sector and is active in the preparation of the new EN ISO 24656 standard “Cathodic Protection of Offshore Wind Turbine Structures”.

Andrew Woodward corrosion expertAndrew Woodward and Chris Matthews

The week starts strongly, and it certainly doesn’t fizzle out. The last of the week’s webinars delivers a ‘two-for-the-price-of-one’ experience (except, of course, there is no cost – all the webinars are free).

Andrew Woodward is Marketing Manager at Connector Subsea Solutions including MORGRIP. Andrew has a BEng and an MSc in mechanical engineering from Aston University. Andrew has over 10 years of experience in technical sales and estimation in specialist applications and joined the MORGRIP team in 2016.

Joining Andrew ‘on stage’ is Chris Matthews, Project Engineer at Subsea……

Chris Matthews joined the MORGRIP team in 2014 shortly after finishing a BEng in Aerospace Systems Engineering at Coventry University. After a short period working with standard products Chris was engaged in a high-profile project for Mechanical Connectors for Deep Water Repairs which lasted 2 years. After that Chris was a leading figure on the engineering team developing the new MORGRIP CLiP Connectors which are the subject of today’s presentation.

The agenda for this week of webinars

Without further ado, let’s take a glimpse at each of the webinars. Each will be a one-hour presentation by the subject expert. A Q&A session via the chat box immediately follows the presentation.

Improving the Corrosion Resistance of Duplex Steel Welds (Dr Roger Francis)

Monday 6th July 2020, 12pm BST

Register for this webinar here

Modern duplex stainless steels have been in common use since the early 1980s, and how to weld these alloys satisfactorily is well understood. Despite this, corrosion failures of welds still occur. This talk will discuss the important parameters to produce satisfactory welds in duplex stainless steels.  There are further things that can be done to improve the corrosion performance of duplex welds, and these are discussed along with test data. It is important that testing over and above that in ASME IX is carried out on duplex weld Procedure Qualification Records (PQRs) and some suitable tests are proposed. The corrosion resistance of welds and parent metal to different sorts of corrosion will be discussed.

Hot Corrosion Mechanisms for Gas Turbines (Dr Adnan Syed)

Tuesday 7th July 2020, 12pm BST

Register for this webinar here

Hot corrosion mechanisms were first proposed more than half a century ago, but we are still learning about them and they continue to be a focus for manufacturers of aero and industrial gas turbines.

The understanding of corrosive salt and target alloys are both crucial topics to enable improved mechanisms. Corrosion mechanisms vary due to the composition of the alloys and deposit salt chemistries.

The concept of acid and basic flux on the alloy surface due to induced deposits on the alloy’s surface is also well defined; however, further investigation is still required.

Along with laboratory corrosion experiments, the use of thermodynamic software is a key tool to help identify the likely phases formed, which in turn enables a better understanding of the mechanisms involved.

The talk will include the possible hot corrosion mechanisms occurring in the gas turbine combustion environment, and support some of the challenges the industry is facing in its understanding and managing of turbine component degradation. The talk will also present the laboratory setup for hot corrosion testing and techniques used for evaluation of material performance.

Improvements of the DNVGL-RP-416 and DNVGL-RP-B401 – Upcoming Revisions (Lars Lichtenstein)

Wednesday 8th July 2020, 12pm BST

Register for this webinar here

This is a must-attend webinar for those working in the wind turbine industry. You’ll receive the inside track on material selection for bolts and stainless steel, and the boundary conditions that should be considered.

The recommended practices issued by DNV GL on corrosion protection for wind turbines are being reviewed internally. Learn what the items and considerations under review are, and become updated on how the process of review is used to address and improve the overall quality of corrosion protection for offshore wind.

The current key DNV GL documents for corrosion mitigation and CP in this sector are DNVGL-RP-0416 and DNVGL-RP-B401. Formally, DNVGL-RP-0416 is issued from Renewables Certification, part of the energy business, while DNVGL-RP-B401 is owned by the oil and gas business. Therefore, this presentation will mainly deal with the items and considerations being dealt with for the revision of DNVGL-RP-0416, but relevant topics in relation to DNVGL-RP-B401 can also be addressed and discussed.

Since 2016, when DNVGL-RP-0416 was first published, these recommendations were applied to numerous offshore wind projects. We have been part of the certification process for many of these projects and could gain experience and feedback on the content we have issued. Generally, there has been positive feedback, but some guidance lacks sufficient detail. Some of these areas need to be addressed to improve the overall quality of corrosion protection for offshore wind.

Several relevant standards have been revised since 2016 (e.g. ISO 12944 or ISO 2063), new standards like VGB/BAW have been introduced, and new ISO standards are currently being written in several working groups. Improvement of the guidance given is needed and possible. We want to address the most relevant items with new revisions of our RPs.

This seminar will provide more guidance on the useful coating lifetime as introduced in DNV-OS-J101:2011 for the first time, and the relation with fatigue calculation and surface preparation. What level of quality is needed at the end of the lifetime? How much effort shall be put into inspection and repair of 15-year-old+ coating systems? You will gain insight on material selection for bolts and stainless steel, as well as what boundary conditions should be considered. This seminar will also study the issue of coating breakdown factors with regards to CP system calculation and on currency drain of buried structures. The revisions of the documents are not yet finished, and therefore input from this event will be able to influence the development of future recommended practices.

Cathodic Protection of Offshore Renewable Energy Infrastructure (Brian Wyatt)

Thursday 9th July 2020, 12pm BST

Register for this webinar here

External surfaces of offshore structures, including offshore wind turbine foundations and tidal/wave energy structures are routinely protected from corrosion by cathodic protection [CP] using aluminium alloy galvanic anodes. Design codes for this are provided by several sources; the most commonly used for offshore wind applications being DNVGL-RP-B401.

These codes have been produced primarily for jacket structures used in deep water for oil and gas developments. They are inadequate for structures required for offshore energy infrastructure such as offshore wind turbine monopile [MP] foundations, tidal turbines, or wave generators – all of which need to be installed in near-shore shallow water environments. For these conditions, there are special considerations over and above those defined in these codes, notably the impacts of higher tidal flow, a greater proportion of the shallow structures being in the tidal zone and of wave action. All result in high levels of oxygenation at the steel/water interface which demand more robust CP designs, both in mechanical and electrochemical terms. The nature of the support structures, and limited scope for lower-cost onshore anode installation, also lead to challenges to uniform anode distribution, particularly on MPs.

Although DNV GL has addressed some of these issues in its DNVGL-RP-0416, written specifically for offshore wind applications, it has not addressed all of the environment issues, and the requirements remain largely biased towards the use of RP-B401 for CP design.

A new International Standard, EN ISO 24656 ‘Cathodic Protection of Offshore Wind Turbine Structures’ is under development to address these issues more fully. It will soon be published for public comment. It will reflect a significant change in the design process for cathodic protection, to reflect the particulars of offshore wind foundations and their environments.

This seminar concentrates on these additional considerations for the design of external CP for near-shore offshore energy infrastructure. It also, briefly, discusses the special and different requirements for internal CP of wind turbine monopiles.

Use of CRAs in Subsea Pipelines and Repair of Clad Pipeline Connections (Andrew Woodward and Chris Matthews)

Friday 10th July 2020, 12pm BST

Register for this webinar here

Since 2009 the MORGRIP team has been engaged with major operators to develop a mechanical connector solution specifically designed to meet the unique challenges of Clad and Lined Pipeline systems. A traditional mechanical connector seals on the outer diameter of the pipe and is used as an alternative to welding for straight cut pipe ends. For a clad or lined pipe this type of connector does not adequately protect the pipe end and parent pipe from the corrosive attack of the aggressive sour line media.

The CLiP Connector was developed over 2 phases of a Joint Industry Project part funded by Chevron and Woodside. The aim of the JIP was to take the existing MORGRIP connector technology and integrate a mechanism to protect the exposed end of a clad pipeline from the aggressive line media after installation.

The seal takes advantage of the corrosion resistant and ductile properties of Alloy 625 when subjected to specially controlled heat treatment as well as extensive testing and track record of graphite in order to create a seal module that conforms to NACE MR0175 / ISO15156-3. The seal forms around all pipeline manufacturing tolerances and even localised irregularities such as internal weld seams. The seal can be easily integrated into existing mechanical connector configurations and is able to be adapted for both diver installed and remote repairs.

The technology qualification was completed to DNVGL-RP-A203 through a combination of analysis, 3rd party material testing, component testing and culminating in full scale testing of a production unit. This resulted in the award of a DNVGL Type approval for the product range in accordance with the requirement of DNVGL-ST-F101 for submarine pipelines and DNVGL-RP-F113 recommended practice for pipeline repair.

Don’t miss out on these webinars

We’re anticipating strong demand for these extremely current webinars. Not only because of the subject matter, but because of the authority of the presenters. Don’t miss out – register now. As the year progresses, we plan to bring you more events that bring the corrosion conversation to you –another example of the benefits of membership of the Institute of Corrosion.

For details about membership of the Institute of Corrosion, visit our membership page.

Ask the Expert

This month, the questions being answered by our corrosion technology experts relate to impressed current Cathodic Protection systems for pipelines and plant piping, and salt contamination of metal surfaces before painting.

Question:
The use of linear MMO sock anode systems are specified by various operating companies for pipelines and plant piping cathodic protection systems. The specifications also state that an effective isolation is not compulsory in a congested petrochemical plant, as the anode current is expected to protect the pipeline closer to the anodes. Should effective isolation be compulsory. If not, what other protective measures should be taken? AN

Answer:
Distributed anode cathodic protection systems are generally used for plant piping protection. Achieving 100% isolation on a complex structure / plant piping is practically difficult which leads to huge current loss to other structures, limiting the cathodic protection on piping. The project specifications developed in the last decade specified linear MMO sock anodes for complex structures to overcome the current drains due to isolation failures. The basic assumption being that the anodes are installed closer to the pipe and hence the CP current will be drained by the pipes due to proximity rather than the earthing electrodes, or concrete rebars, a few metres away from the anode and the pipe. The same concept has been applied on several plant piping and pipeline projects, and current drains to earthing rods and concrete rebars are evident even with a sock anode system. The cathodic protection levels on the piping improved after fixing the failed isolations. It is known that an effective isolation is the key to achieve cathodic protection of pipes irrespective of the type of anodes being used.
It has also been observed that IR free coupons installed in the vicinity of sock anodes are influenced by the anodic current during IR free / Instant OFF potential measurements. This is an additional information for the CP designer to consider while designing a sock anode system. The coupons that are very close to the anode polarise positve and affect the pipeline polarisation when connected to pipes. Coupon potentials turn more positive during Instant OFF as it interferes with the anode. IR free coupons and reference electrodes must be placed away from the sock anodes, or the use of IR free coupons must be avoided on a sock anode system to avoid detrimental effects.
Ashokan Gopal, Corrosion Technology Services Europe Limited.

Question:
What is an acceptable level of salt contamination on a surface before applying a protective coating? Does this level vary with the type of coating applied, or the end use? JW

Answer:
What at first seems a simple and straightforward question is not a simple and straightforward answer! The issue of salt contamination has always raised a heated debate since the late 80s early 90s when people started to realise that residual salts were a main cause of premature breakdown of coatings. Prior to this the most likely level of testing was the use of a potassium ferricyanide test paper that was applied to areas of pitting, to see if there was any residual ferrous salts present. A qualitative, not a quantitative test so we only know if ferrous salts are present or not, not how much, so is of limited value. Since then, a whole gamut of possible salts has been recognised as potentially being present on the surface of prepared steel, still the ferrous salts, but most importantly the presence of sodium chloride (NaCl). NaCl has always been known to be a problem for coatings, it took, however, a while for people to realise that the risk was from osmosis, and the creation of osmotic blisters containing a strong saline electrolyte.

Osmosis is the process whereby two solutions on either side of a semi-permeable membrane try to reach a state of equilibrium regarding their concentration. If you have a strong solution on one side and a weak solution on the other, water will pass through the membrane attempting to dilute the strong solution until it is isotonic with the other side of the membrane. From this we can therefore deduce that salts become a major issue in either immersion or very damp conditions, blistering is not going to be very likely in a dry, air-conditioned environment. The next thing to consider is the permeability of the applied coating, this will be affected by a multitude of factors but mainly the density of the coating matrix and its resistance to the flow of water through it, and the applied thickness. Also, the concentration gradient across the membrane must be considered.

When it comes to coatings, there are several considerations, particularly when using certain words; glass flake is a particular one when it comes to permeability! Glass flake coatings come in a whole range of varieties of binder, flake size, flake shape and flake density. A cheaply made ground glass powder in a cheap epoxy binder applied at low DFT will never perform as well as a proper, high density glass flake with a flake size of 1/16” or larger, trowel-applied, solvent free polyester based coating, with a DFT of over 1mm!

There is then the issue that stainless steels, duplex and super duplex materials suffer from chloride induced stress corrosion cracking and with these, when in a high-risk application, there is a need to see chloride ion contamination as close to zero as is practicable. This is not helped by the fact that many epoxies have chlorides in their formulations, so regardless of how low you get the contamination on the surface, the wrong selection of coating immediately undoes all the hard work!

As can be seen, there is no one answer fits all, unless you take a totally risk aversed viewpoint, where there is a zero tolerance.

There are two ‘normally acceptable’ values that tend to be bandied around and these came originally from the NORSOK M-501 guidelines:
“The maximum content of soluble impurities on the blasted surface as sampled using ISO 8502-6 and distilled water, shall not exceed a conductivity measured in accordance with ISO 8502-9 corresponding to a NaCl content of 20 mg/m² .”

20mg/m² was adopted for immersion and 50mg/m² for atmospheric maintenance. These numbers are not based on any particular science but are pretty arbitrary and were there as a guideline. The next problem is the interpretation – is it total salts? a specific salt such as sodium chloride? or is it just the chloride part? Having defined what you deem necessary to test for, the next problem is how do you test for it? This opens another major can of worms!

In all honesty, there is not a single answer, you need to look at the individual requirement. The coating manufacturers should have done the necessary testing in a variety of scenarios with their products, and should be able to confirm what level of contamination is acceptable and what DFT of the material is required to give the required performance in the situation envisaged. Independent verification of the testing by a third-party test lab is a very useful indicator of the potential performance to confirm manufacturers’ claims.

Therefore the simple answer is to use the 20 and 50 mg/m² for carbon steels etc. and as close to zero for S/S, duplex and super duplex as a safe bet base guideline to work from, but it is essential to make sure that the materials, specification and environment are assessed together with making sure that the most suitable choices are made to meet the performance needs.
Simon Hope, Consultant Technical Authority, Auquharney Associates Ltd.

Readers are invited to submit generic (not project specific) questions 
for possible inclusion in this column. Please email the editor at, 
brianpce@aol.com

Fellow’s Corner

The third article in this series from ICorr Fellows who have made a significant contribution in the field of corrosion is by Bill Hedges, Vice President of the Institute of Corrosion, FICorr, FRSC, FNACE and CEng.

Corrosion Monitoring and Inspection

Corrosion monitoring and inspection are essential components of a corrosion management programme and numerous books, papers and conferences are dedicated to these subjects. This article focuses on some key points of these activities and the reader is encouraged to review the literature for more detailed information.
To minimise safety, environmental and business risks whilst maximising reliability, it is essential that equipment is maintained in a condition appropriate for the service required. Equipment in this condition is described as Fit-for-Service (FFS), i.e. the equipment can operate safely under defined operating conditions for a defined operating period. It should be noted that equipment that is FFS does not have to look nice or be corrosion free – although that is often desirable for other reasons! Corrosion is one of many possible degradation mechanisms that can negatively impact the condition of equipment and ultimately render it not FFS. Corrosion monitoring and inspection are used to determine if equipment is FFS and to predict how long it will remain so.
The definitions of corrosion and inspection can become blurred but broadly inspection involves quantifying the safe, usable wall thickness of metallic equipment and identifying defects such as thinning, cracking or pitting, caused by corrosion. Inspection is usually the most accurate way to determine current equipment condition but has the obvious disadvantage that any damage that is detected has already occurred. Inspection is therefore a lagging indicator.
To complement inspection methods, a leading indicator is needed; something that will identify that degradation is occurring and provide enough warning so that an intervention can be implemented well in advance of the problem impacting FFS. In practice a true leading indicator is difficult to obtain but this is what corrosion monitoring strives to do.
For both corrosion monitoring and inspection it is critical that the correct locations are selected. This requires a full understanding of the corrosion threats, the probable corrosion rates and the consequence of failure, i.e. a risk-based approach.

Corrosion Monitoring
Historically corrosion monitoring was exclusively associated with the measurement of corrosion rates. However, this definition has been extended to include the measurement of the performance of corrosion control barriers, e.g. the availability of corrosion inhibitors, the condition of coatings, or the electrical potential of equipment under cathodic protection control.

Corrosion Rate Monitoring
In broad terms corrosion rate monitoring is the measurement of a representative corrosion rate for a given piece of equipment exposed to a corrosive service. There are several techniques that can be used either as standalone or in concert with each other. Ideally corrosion monitoring is designed to provide real time feedback on the corrosion control process. It is important to remember that any given monitoring technique will have limited accuracy and sensitivity, and should be chosen to provide appropriate information. Monitoring is used for corrosion on both internal and external surfaces, but for this article only internal monitoring is discussed. Traditional methods for internal corrosion monitoring include:
i. Mass (weight) Loss Coupons.
ii. Electrical Resistance (ER) Probes.
iii. Electrochemical Monitoring (e.g. linear polarization resistance (LPR), 
AC Impedance).

Clearly there is a cost to installing and running corrosion monitoring programmes and this needs to be balanced against the value that they will provide. For probes, the ideal situation is to have them hard wired or wirelessly connected into the equipment control system which is best done during design and construction.

There can be a significant operating cost to manage coupons and probes which obviously depends on the size of the programme. Insertion and retrieval of coupons and probes into pressure containing equipment may present safety risks and must be done by specially trained personnel. Analysis of coupons requires laboratory facilities and the analysis of data requires appropriate training. These contribute to the cost of the programme and so the value of the data must be carefully considered. Monitoring data should never be considered as simply nice to have. If the data are not actively used and acted upon it begs the question of why invest in the expense and effort of installing corrosion monitoring facilities.

Corrosion Barrier Monitoring
To reduce corrosion rates to an acceptable level, corrosion engineers use a variety of mitigation methods known as barriers. These fall into two broad categories as follows:
i. Passive Barriers: these are barriers which require little or no active management during the lifetime of the equipment, e.g. the use of a material that is resistant to corrosion in the specified fluid.
ii. Active Barriers: These are barriers that require active management by corrosion engineers. This can range from periodic visual inspection to monitor the condition of paint coatings to daily adjustment of corrosion inhibitor injection pumps.

It should never be assumed that because a barrier has been installed it will always work as designed. Where active barriers are employed it is essential that their performance is monitored to ensure they continue to perform as designed over the lifetime of the equipment. This is known as corrosion barrier monitoring, i.e. a corrosion monitoring programme is not just about measuring corrosion rates.

A good corrosion management programme will have at least one barrier in place for each credible corrosion threat and each of these barriers should be monitored to ensure they are working as designed.

Inspection
The majority of inspections are carried out using well-established techniques that have been available for many years, i.e. Visual Testing (VT), Ultrasonic Testing (UT), Radiography Testing (RT), Magnetic Particle Testing (MT) and Dye Penetrant Testing (PT).

Many of these techniques have been built into both internal and external tools, e.g. intelligent (smart) pigs, drones and subsea remote operating vehicles (ROVs).

Many inspection instruments are now small enough such that they are truly portable and can be handheld by a single person. Inspection equipment can also be permanently installed on facilities to provide point measurements at known defects or more extensive, circumferential or longitudinal coverage. Another important development is the increased use of remotely controlled crawlers and drones which can carry cameras to locations that are difficult or costly to access, such as subsea pipelines, flare stacks and offshore platform jackets.

An example of a Corrosion Management Dashboard.

An example of a Corrosion Management Dashboard.

An important development in radiography is the widespread use of digital radiography which uses electronic detectors instead of traditional film plates. The resolution of the digital “plates” provides very high-quality images with each pixel offering 250µm resolution. The high sensitivity also allows either lower strength radiation sources to be used or shorter exposure times. In addition, modern data processing provides very fast data acquisition and analysis of images which allows the images to be seen in almost real-time.

Collection and Analysis Data
Following data acquisition by corrosion monitoring and inspection, it is paramount that the data are stored, analysed and interpreted.

Real-time transmission of corrosion data from electrically based monitoring (e.g. ER, LPR, oxygen probes) has been available for many years although it required the installation of hard wiring from the probe to a control centre. In recent years there have been significant advances in the availability and reliability of wireless communications. This has enabled data to be transmitted relatively inexpensively from corrosion monitoring locations in real time.

Many companies provide software that can take multiple data inputs and correlate them with the corrosion monitoring data. As an example, taking temperature, pressure and flow rate data from a pipeline to estimate an unmitigated corrosion rate. These data are then presented in a corrosion dashboard which can be seen at any location around the world. The above figure shows a typical dashboard that displays real time fluid flow rates, velocities, sand rates and estimated corrosion rates.

Future Considerations
Inspection techniques can measure equipment wall thicknesses very accurately but historically they have required skilled technicians to make the measurements using portable equipment. The cost of this has meant that repeat inspections were undertaken at a frequency of 1-5 years. However, with improvements in technology, the use of permanently installed inspection equipment has blurred the boundary between what was traditionally referred to as Inspection and Monitoring, and the use of inspection techniques as ‘real-time’ corrosion monitoring tools has become more common.

These non-intrusive, highly sensitive technologies are able to work through solid external coatings (e.g. FBE, PE, 3LPP). They are increasingly becoming the preferred methods for corrosion monitoring going forward and offer the option to eliminate intrusive monitoring and the risks associated with it.

Guided wave UT is increasingly being used to monitor long lengths of piping and pipelines. It is probable that these techniques will be used to provide close to 100% coverage of equipment to provide real time measurements at all locations. This would be a key step towards intelligent equipment which self identifies problems.

Corrosion monitoring and inspection programmes can generate large volumes of data which are often reviewed in isolation. There have been significant advances in data analytics (so called “Big Data”), artificial intelligence and machine learning. These technologies can rapidly analyse vast quantities of structured (e.g. data) and unstructured (e.g. reports) information to provide insights that may have been missed.

Finally, engineers and technologists continue to find new and improved methods for monitoring and inspection. Perhaps one day corrosion may be eliminated but until then it is certain that better methodologies for monitoring and inspection will continue to appear.

Young Engineer Programme (YEP)

ICorr’s Young Engineer Programme once again broke new ground as it held its first ever meeting online in May, for the reveal of its 2020 case study.

The grand surroundings of the Royal Over-Seas League might have been replaced with the homespun comforts of participants’ living rooms, but the content of the meeting remained as topical as ever with Steve Paterson from Arbeadie Consultants Ltd presenting the 2020 case study for the seven participating groups.

Focusing on an onshore titanium pipe corrosion failure, Steve described a scenario where several leaks were experienced in the piping at an onshore glycol desalination plant that required further investigation, giving the participants plenty to think about ahead of presenting their findings in November.

As an experienced technical expert with a deep knowledge of subsea engineering and corrosion management systems, Steve’s puzzling scenario ensured that the 32 participating young engineers – representing 19 companies, each with a wide and interesting variety of specialist backgrounds – had plenty to discuss on the evening.

The young engineer’s broad set of specialities include mechanical and materials engineering, welding, materials and more. These were all put to the test when discussing the desalination plant, which is used to periodically remove the salts from mono-ethylene glycol, used for hydration and corrosion control in gas pipelines from three offshore fields.

With the help of a mentor assigned to assist each group, the young engineers were posed with problems at the end of the presentation. These included proposing root causes for the defect, how to perform a corrosion risk assessment to determine if the plant is safe to operate, suggesting alternative materials, and identifying what mitigation options could be applied to prolong the service life of this section of the desalination plant, among others.

The YEP has been running for a number of years and delivers a technical competency framework that’s consistent with the Institute of Corrosion’s professional standards, to help prepare graduates for entry into the industry with a broad range of knowledge. As well as providing an opportunity to network with likeminded professionals, the programme also offers participants a stepping stone into the industry, and is the first stage in achieving MICorr and CEng status.

In what might be the first of many online meetings, the evening ran according to schedule, although participants and guests had to make their own tea and coffee during the scheduled break. Prior to that though they were entertained by Tim Evans, Caroline Allanach and Danny Burkle who offered a reflection on their 2018 winning case study.

Caroline and Danny discussed how they approached the case study and the fantastic resulting prize of a trip to the 2019 NACE Conference in Nashville, while Tim provided a critical assessment of their reaction and solution to the failure that occurred.

The case study was concluded by a series of questions and answers, before Trevor Osborne from Deepwater Corrosion Services brought the first ever online YEP meeting to a close with a message of thanks. The participants will attend four more lectures before reconvening in November to present their case study.