Passive Fire Protection (PFP) Epoxy Coating Inspector Level 2 – Online

Passive Fire Protection (PFP) Epoxy Coating Inspector Level 2 – Online

Coating and Inspection Training, Fire Proofing Inspector

Passive Fire Protection (PFP) Coating Inspector (Epoxy) Level 2 – Online

Why attend this course?

The changing market dynamics and a number of PFP failures on major new construction projects will dictate the need for a more rigorous fire protection coatings Inspector course in order to further improve competency in this safety critical area of our market. The Institute of Corrosion and PFPNet have collaborated to develop the first detailed training programme for inspectors and technicians, written and produced by experts in this field who have extensive, practical ‘real world’ experience.

The purpose of this course

The purpose of this NEW course is to train and examine Inspectors of epoxy intumescent Passive Fire Protection (PFP) on the inspection of common types of epoxy coatings used to protect against hydrocarbon fires on installations for both on and offshore facilities.

The main theme of this course

This course is completed remotely using our online learning system. The examination is held remotely on two dates each month.

Special Note

It has been agreed by PDTC (ICorr) to add an experience assessment to all ICorr certifications for personnel engaged in painting and coating inspection. If certification is required, candidates must as a minimum have held ICorr Painting Inspector Level 1 or Coating Inspector Level 1 for a period of two years. It is possible to transition across from other certification schemes here. If a suitable qualification is not held, then dispensation to gain certification may be given if an individual has 5 years’ experience relating to painting or coating inspection.

Why Online? & Benefits of Online

The online course has been developed so candidates can complete the training material at their own pace and in their own time. The examination is also completed remotely on two dates each month.

Online Learning brings the following key benefits:

  • Stress-free learning environment
  • Learn in your own time and at your own pace
  • Course content can be viewed as many times as you like prior to examination
  • Ability to continually study for your examination
  • Less time out of work
  • Save on accommodation costs
  • Save on transport costs
Overview

This course assumes all candidates hold ICorr Painting or Coating Inspector approval (any level) and therefore have a knowledge of inspection philosophy, surface preparation, anti-corrosion coatings and how to use common inspection instruments. The course will cover the inspection of modern types of Passive Fire Protection as found on hydrocarbon installations for both on and offshore facilities. This will include structural members, decks and bulkheads and storage or process tanks and associated pipework. Mechanically fixed methods are not covered.

Course Content
  • Overview of passive fire protection
  • Development process of an epoxy PFP system
  • Factors affecting durability
  • Common defects
  • Typical equipment used by an Inspector
  • Health & Safety requirements for site working
  • Documentation to be reviewed
  • Role of the Inspector on site
  • What an Inspector monitors during PFP application
  • Inspection & Reporting
Course Details and Price

£650.00

PLEASE NOTE: Online courses now have a multi-booking discount

This course is completed fully online, including remote examination.

To find out more information and book your training please contact our customer services team using the information below.

Email Us
enquiries@argyllruane.com. 

Call Us
+44 114 399 5720

The problem with black powder deposits

The problem with black powder deposits

Fellows Corner

The article by Al-Otaibi and Deshmukh (p23 Corrosion Management September/October 2020) provided important insights into how intractable black powder problems can be in hydrocarbon systems. It also reminded Chris Googan of a recent investigation into a black powder problem on a floating production storage and offloading (FPSO) installation. Here’s his anonymised summary of that case…

The Problem

The FPSO operated independently under contract to a major oil producer. In around 2014, a black powder problem became apparent in the gas processing system. The rogue solids periodically blocked strainers at the gas cooler inlets, necessitating shut-down of one of the twin gas processing trains. To avoid flaring the gas, the rate of oil production had to be reduced. Unless the FPSO operator could demonstrate that the black powder problem originated subsea or downhole, its contract required it to carry the costs of unblocking the strainers. It also incurred financial penalties arising from the cut-backs in oil production.

The FPSO Operator’s Investigation

The FPSO operator embarked on an investigation which, unfortunately, lacked both objectivity and any corrosion specialist support. Every time a strainer blocked, samples of the black powder were sent to a commercial laboratory where they underwent comprehensive, and not inexpensive, analysis: wet chemical, infra-red and x-ray spectroscopy and x-ray diffraction (XRD). The FPSO operator’s desire was that the results would identify corrosion of the oil major’s subsea infrastructure, or solids from the reservoir, as the source of the deposits.

In parallel investigations, the FPSO operator also embarked on an intensive, and likewise not inexpensive, campaign of non-destructive testing (NDT) of its own carbon steel pipework and equipment upstream of the strainers. Its ambition was to demonstrate that the topsides gas processing system was not corroding; so the black powder must be originating subsea.

Analytical Results

Chemical Components
Table 1 summarises a typical set of results from some of the many analyses of iron-based deposits collected from the strainers. It also records the presence of other (non-iron) salts found.

If the information in Table 1 were not perplexing enough, drilling down to the crystallographic nature of the compounds, as revealed by XRD, prompted even more head scratching. For example, the sulfate minerals observed included: szomolnokite, melanterite, jarosite and rozenite, which hardly ever appear in the corrosion literature. None is expected to form in anoxic hydrocarbon production environments. It seems most likely that the sulfate deposits were formed by the post-sampling oxidation of iron sulfide corrosion products when exposed to air. This process would be in addition to the known conversion of iron sulphide to iron oxides in the presence of atmospheric oxygen. (It seems that the need to maintain samples under an inert atmosphere was not fully appreciated by all involved). The relative absence of carbonate (siderite) from the majority of samples suggests that the corrosion products were formed when the H2S to CO2 ratio in the gas favoured the formation of sulphide ahead of carbonate.

The whole assessment, however, was complicated by the bewildering multiplicity of other iron-bearing compounds observed in the deposits. These included sulfides: pyrite, mackinawite, pyrrhotite, marcasite and greigite. There were also oxides and oxy-hydroxides: geothite, lepidocrocite, akageneite, wuesite, magnetite and maghemite. Thus, the vast majority of the deposits in the strainers was corrosion product; but the plethora of crystalline forms obscured the corrosion mechanisms; and provided no information at all on where the corrosion had occurred.

In addition to iron corrosion products, small amounts of halite (NaCl) were detected in some; but by no means all, of the debris samples.

Chasing Isotopes

The nucleus of the iron atom has 26 protons; but the number of neutrons combined with these protons can vary considerably. This means that there are 34 known isotopes of iron. Most are exceedingly rare, and of no interest for our purposes. They undergo radioactive decay to daughter isotopes of manganese, chromium or cobalt with half-lives ranging from nanoseconds to millions of years. On the other hand, there are three stable isotopes: 56Fe, 57Fe and 58Fe, with relative abundances of (approximately) 91.75%, 2.12% and 0.28% respectively. Another isotope, 54Fe, has a decay half-life of a mind-boggling 4.4×1020 years; so is stable as far as we are concerned. It makes up the remaining 5.85% of the iron atoms found in nature.

It has been known for some time that there are slight variations in the iron isotope balance for steels, depending on the ores from which they are derived. This prompted the FPSO operator to commission isotope analysis of samples of the debris, and of the process system steelwork. Its expectation was that this would demonstrate that black powder iron did not originate from the gas system steel. The ratios of 56Fe to 54Fe, and 57Fe to 58Fe were measured for nine steel samples and ten debris samples. To cut a long story short: the results were inconclusive. The span of measured isotope ratios observed in the deposits overlapped the span of ratios observed from the steel specimens. Beyond that, no conclusion as to origin could be drawn.

Inspection Results

As with all such exercises, the NDT campaign produced a glut of data, Unfortunately, however, there had never been a base-line wall thickness survey of the as-built pipework. The best that could be concluded, therefore, was that there had only been “marginal” metal loss compared with the nominal values. The FPSO operator interpreted this as supporting its case.

The Corrosion Assessment

After three years of heroic analytical endeavour, the FPSO operator decided it was time to involve a corrosion specialist in the investigation of this corrosion problem. I was commissioned to review the voluminous data and come up with a report that determined whether the operator or the oil major held the responsibility for the black powder problem.

My analysis took a lot less time than my client expected. Instead of delving into the minutiae of what was in the black powder, I focussed on what was not there. The missing ingredient was the salt (halite).

If, as hoped by the operator, the black powder originated subsea, then the only mechanism for it to have entered the gas production system was in aerosol droplets of produced water carried over with the gas from the slug catcher or gas-oil separators. Any such droplets would have to possess a much greater salt content than iron compound content. Incoming produced water analyses showed typical values of 13 000 mg/l chloride, less than 130 mg/l in total of suspended solids, and less than 1 mg/l of soluble iron. Thus, any droplets carried over would have had to contain hundreds, more likely thousands, of times as much halite as iron. Although there was evidence of isolated instances of produced water carry-over, analysis of the solids, and of the water separated from the gas system, simply failed to find anything like enough chloride to tie the iron to a subsea source.

The remaining plank of the FPSO operator’s case, namely that its gas piping was exhibiting only “marginal” corrosion was also soon jettisoned. Elementary calculations, based on the surface area of upstream off-gas pipe wall exposed, showed that even very low corrosion rates, well below those predicted by CO2 corrosion rate algorithms, would result in ample iron-based corrosion product to account for the observed quantities of black powder.

Lessons Learned

Numerous lessons emerged from this exercise. Some related to the original corrosion engineering of the FPSO’s gas processing facilities. For example, hindsight prompted reconsideration of the original design decision to omit the option of being able to inject vapour phase corrosion inhibitors into the system. It also forced a re-sizing and re-design of the strainers.

From the corrosion perspective, however, I offer two learnings. The first, unsurprisingly, is that it is a good idea to involve a corrosion specialist from the beginning of a corrosion investigation. The second, and perhaps more difficult to ensure, is always to keep an open mind when embarking on a corrosion failure analysis. Conducting the exercise with a pre-disposition to an intended outcome invites the risk of a biased and confused investigation.

Chris Googan, antiCORR

Fellows Corner

Fellows Corner

Fellows Corner, Uncategorized

Material Integrity Assessment of Onshore Assets

Onshore oil and gas assets are vast and usually cover a large area. These can refer to all upstream facilities i.e.  facilities used for production and stabilisation of crude, or downstream facilities i.e., refining facilities. Upstream facilities can be divided into off-plot facilities e.g., wellheads, wellhead piping, flowlines, remote manifolds, trunklines/pipelines,
and on-plot facilities e.g., stabilisation systems, separation/dehydrations systems, flare systems, produced water systems, utilities systems,
storage facilities etc.

Typically, these assets are designed for a minimum of 25 years but in the real sense they are used for a longer period i.e., until total reservoir depletion or a halt in production due to global oil and gas economics. Thus, these assets need to be maintained consistently and occasionally optimised to aid production.

A Materials Integrity Assessment (MIA) is a multi-disciplinary review of materials and integrity of an operational asset with a view to mitigate failure or optimise production. This short article outlines the process for undertaking a MIA of an upstream facility.

A MIA can either be proactive or reactive in nature. These objectives are broadly categorised into the following:

  1. To assess suitability of materials when a proposed brown field modification will introduce new production fluids/operating parameters to an existing facility.
  2. To assess the material/integrity threats due to a change in the current operating conditions that can lead to a failure or loss of containment e.g., unexpected reservoir souring, sand production, oxygen ingress, build-up of microbial activity etc.
  3. To proactively ensure the assets are operating within defined limits.
  4. To proactively apply learnings from other facilities and global best practice.

The scope of an assessment can be the whole upstream facilities. or sections of the facility. This needs to be determined by the Client with the above objectives in mind. The scope will determine the duration of the project (from weeks to months) and the number of disciplines involved e.g., where only an on-plot scope is envisaged, there will be no requirement for a pipeline integrity engineer etc.

MIA Methodology

The methodology, and steps of the assessment are shown in figure1 below:

The scope/objective is defined by the Client in conjunction with the MIA Lead. The corresponding disciplines are defined, and personnel nominated.  It is advisable to have a core team and an ad-hoc team on an on-call basis, a typical team comprises the disciplines shown below:

The ICP (Independent Competent Person) should be an experienced professional with no interest in the asset/facility who will be responsible to vet the assessment and to provide guidance where required. Individual and group roles and responsibilities are then defined with the expected time frame by the MIA Lead. It is critical to note the assumptions and exclusions at this stage of the project.  Where there are known integrity concerns, these needs to be highlighted on a draft heat map displayed on a base PFS/PEFS drawings.  The heat map tends to zero in on the areas that need special attention especially when undertaking a review of a very big asset. It also easily shows areas with similar integrity issues or failure patterns that will help with the assessment. 

Data gathering and review is the most critical phase of a MIA.  The data to be reviewed includes. but not limited to, the Facility Design Basis, Plant Operating Manual, Material Selection Reports, Corrosion Management Manuals, Inspection/Monitoring Data, CP Monitoring Data, Failure/Leak registers, Maintenance Plans/Reports, Trending Reservoir Data etc. Some well-organised and maintained facilities/assets will have this information readily available while others may have insufficient information.

Where the available data is insufficient, then several assumptions will need to be made. As an example, in a particular project where there was no baseline inspection data or any subsequent data after seven years of operation, the integrity assessment was then based on a greenfield (new) corrosion modelling. After going through the material selection process, this was then compared with what was physically on the ground and an evaluation made as to whether the right material selection had been made, and the expected remaining design life based on the existing process parameters. This comparison formed the basis of the subsequent recommendations.

A site/field visit is essential as it gives the team the opportunity to visually inspect piping, flowlines and equipment. It also serves as a verification process of the data provided or any of the identified integrity issues.
The visit should also include interviews with key operation and inspection personnel who will be able to give their observations of any changes in the field and more clarity on the plant operations. Pre-prepared questionnaires are recommended for these interviews.

Interdisciplinary Peer Review Workshop

After the site/field visit, the team write up their findings based on the areas of responsibility allotted to each person. The whole write up is then discussed as a team to fine tune and align the findings. On completion of the interdisciplinary review, it is sent to the ICP who will then have a peer review with the whole team. This serves as a form of technical challenge
of the whole exercise and the conclusions/ recommendations.

The report presentation should include a high-level summary using the traffic light system showing the overall status of the asset with the corresponding updated heat map. This high-level summary is based on a more detailed report of the individual areas. This report needs to include a full explanation i.e., scope/objective, overview/history of the asset, findings, where possible photographic evidence and recommendations. This should also be presented visually in a table. An example is shown (top of page 21) based on the earlier heat map.

Recommendations/Conclusions

The recommendations should list out action points to be carried out by the Client in order to verify the integrity of the onshore asset.  These recommendations generally fall into the two categories outlined below:

Short term (less than 6 months) – These require urgent remedial actions/mitigation to avoid loss of containment of hydrocarbon inventory.

Long term (more than 6 months) – These require non urgent remedial actions to be undertaken over a course of time. Advisably between 6 months to 3 years depending on operational constraints.

The completion of the MIA is the presentation of the report (including a power point) to the Client.  Any grey areas need to be clarified to the Client so the recommendations can be addressed within the given time frame.

A Corrosion Management Program (CMP) manual will include the process design and operating conditions, basis of materials selection, corrosion mitigation, inspection strategy as well as corrosion monitoring methodology. The manual needs also to include the risk assessment of critical assets to determine risk severity, monitoring techniques to ensure that the assets can be operated in a safe and reliable manner and the appropriate inspection methods to manage identified risks to maintain the integrity of the critical upstream surface facilities assets. It should also highlight the critical integrity operating window (IOW) parameters and IOW limits to be maintained during service. An IOW programme, its importance, and how to establish
IOW to enhance asset integrity is discussed in detail in reference 2. 
The CMP manual needs to be revised at regular intervals to highlight recent inspection results, risk assessment data as well as changes in process conditions and additional monitoring requirements.

Corrosion monitoring as documented in a CMP manual can be conducted using a number of direct and indirect monitoring techniques, and the merits and limitations of each monitoring technique need to be considered. For effective corrosion monitoring multiple monitoring strategies need to be used and the collected data needs to be analysed along with appropriate process data.  Details of various corrosion monitoring techniques for field applications can be found in the recently revised NACE publication (3). Installing coupons and corrosion monitoring probes can be useful tools for internal corrosion monitoring.  These are considered intrusive monitoring types as they are exposed to pipeline interiors through appropriate access fittings. Proper safety precautions, following the work permit procedures, along with the deployment of suitably trained personnel are necessary for safe removal and installation of coupons from the pipelines during service.  The NACE document “Preparation, Installation, Analysis and Interpretation of coupon data in oil field operations” serves as a useful guideline (4). Corrosion coupons are usually removed at 60-90 day intervals in order to establish long term corrosion rate trends, while the probes are useful to monitor the corrosion rates in real time. Suitable display of the probe’s output in the facility control room will enable the continuous monitoring of corrosion rates, and to alert the operating personnel in the event of higher corrosion rates in order for the required corrective action to be taken. Both wired and wireless configurations are available. The economics need to be taken into account before selecting suitable corrosion monitoring solutions. For pipelines requiring corrosion inhibitor injection, it is essential to have the probes/coupons installed upstream and downstream of the corrosion inhibitor injection point to monitor the performance of corrosion inhibitors. For reliable field corrosion data, it is essential to install the coupons at locations where corrosion is occurring, or most likely to occur, such as high velocity zones, water accumulation spots, etc. Careful location selection is vital since installing the monitoring devices at incorrect locations could obscure the data obtained and its analysis. Linear polarisation probes and electrical resistance probes are used for routine field corrosion intrusive monitoring of the process piping. Linear polarisation probes are commonly used in water systems, while electrical resistance probes can be used in higher resistivity environments. Formation of scales such as sulphide scale, sand erosion, oily/wax deposits at the sensor elements, can affect the accuracy of collected data. As a result, the collected data needs to be analysed carefully to establish a reliable base line reference for meaningful intrusive internal corrosion monitoring data.

In case of nonintrusive monitoring, probes such as thickness measuring sensors using ultrasonic principles can be installed at plant piping exteriors where continuous piping wall thickness monitoring due to corrosion/erosion is warranted, and a number of such systems are commercially available. These sensors can be installed at multiple locations and the wall thickness data, sensor battery life, and the temperature data, can be communicated in real time to the operating facility control room. The main advantage of nonintrusive monitoring is that the monitoring can be conducted when the plant is in service. In addition, critical piping at higher operating temperatures, and at elevated and inaccessible locations can be monitored.  This approach offers cost-savings by eliminating the scaffolding requirements especially for elevated plant piping sections as well as avoiding the costs associated with the operating facility downtime to conduct the conventional thickness monitoring which would otherwise be required. By analysing the collected data, proactive corrective measures to mitigate piping corrosion along with scheduling the piping replacement in advance with the maintenance and operations team can be carried out. This approach enables the monitoring of the critical piping wall thickness condition to prevent the loss of containment due to internal corrosion thus facilitating the operation of the plant assets with highest safety and integrity, as well as to minimise HSE related events. As well as ultrasonic sensors, other methods such as eddy current testing, electromagnetic field mapping and battery free ultrasonic sensors are also considered nonintrusive monitoring types.

To manage critical upstream assets, microbiologically induced corrosion (MIC) also needs to be monitored and managed whenever applicable. Periodic process water sampling to monitor the planktonic bacterial counts, dissolved oxygen content, biocide residuals can be carried out. In oil and gas systems bio-film monitoring probes, samples from removed pipe sections, debris collected during pipelines scraping to monitor the sessile bacteria present in the system along with water quality parameters, provide good information (5).  A number of test kits are commercially available to quickly monitor the biocide residual in the field and to initiate the required corrective actions. It is equally important to document the results and the implemented corrective actions to establish sound historical records.

To mitigate external corrosion threats, parameters such as periodic cathodic protection (CP) potential, current flowing in the structure, CP rectifier potential/current output levels, anode bed condition of underground assets, need to be monitored and managed within acceptable limits. Most of the underground carbon steel piping systems are usually protected by suitable protective coating systems supplemented by properly designed cathodic protection systems. Periodic visual monitoring needs to be carried out at excavated sections of pipelines to inspect the coating condition and to mitigate any external corrosion threats, and the monitored data along with inspection results should be documented.

When selecting the optimum corrosion monitoring solution from the wide range of available options for external and internal corrosion monitoring, the engineering and operational requirements and monitoring objectives, need to be considered, and thus by implementing a robust corrosion monitoring system combined with an effective data analysis, inspection and maintenance strategy, timely remedial measures, the critical upstream oil/gas assets’ integrity can
be managed in an efficient and sustainable manner.

Dr. H.S. Srinivasan, Saudi Aramco

References:

(1) API RP 571-2020 Damage Mechanisms Affecting the Fixed Equipment in the Refining Industry.

(2) API RP 584-2014 Integrity Operating Windows.

(3) NACE TR3T199-2020 Techniques for Monitoring and Measuring Corrosion and Related Parameters in Field Applications,
Houston, TX.

(4) NACE SP0775-2018 Preparation, Installation, Analysis and Interpretation of Corrosion Coupons in Oil field Operations, Houston TX.

(5) TM0194-2014-SG, Field Monitoring of Bacterial Growth in Oil and Gas Systems.

Ask the Expert Post – Issue 164

Uncategorized

Question:

How do you measure electrical continuity of steel in concrete, and why is it important?  BG

Answer:

As reinforced concrete structures age, the steel can become increasing vulnerable to corrosion due to the ingress of chlorides or atmospheric carbon dioxide [1]. Electrochemical techniques can be used both to measure the corrosion and to control it.  Reference electrode potential mapping is widely used on bridges exposed to deicing salts and structures exposed to marine conditions to map the extent and risk of corrosion [2]. Cathodic protection, along with lesser used techniques such as realkalisation and chloride extraction, are all well documented treatments with ISO and European standards [3,4,5].  All of these processes require that for the area under investigation or treatment, there is a direct metal-to-metal contact between all the steel bars in the reinforcing cage that is being assessed or protected.  In the absence of such connections, under cathodic protection, stray currents may occur, leading to the formation of anodes where current leaves a disconnected reinforcing bar, leading to corrosion.  If electrochemical measurements are being taken then any separation between rebars can lead to a cell with its own potential, giving misleading measurement of the steel to reference electrode potential.

This may seem a simple thing to measure, but out in the field with limited equipment it is important that operatives and engineers have clear method statements for carrying out measurements and criteria for defining continuity, whether carrying out steel potential mapping with a reference electrode and high impedance voltmeter, or installing a cathodic protection system.  The problem is that concrete is a damp medium, with high resistivity, and there are multiple parallel connections between reinforcing bars.  Before a steel cage or other structure is embedded in concrete or immersed in water, it is easy to measure the electrical continuity accurately with a digital multimeter or a resistance meter such as a Megger or a Nilsson meter.  Once embedded in concrete, and especially when corrosion is initiated, it is harder to be sure that there is metal to metal contact.  Stirrup steels round the main bars in beams can be a particular problem once corrosion initiates.  Some older structures have very light reinforcement and even electrically separated mats of steel.  Considerable effort may be needed to establish continuity both for assessment and when applying cathodic protection.

This issue was addressed in 1990 by Jack Bennett.  Jack invented the ‘Elgard’ anodes for cathodic protection of steel in concrete along with many other products. As part of the development work, he carried out laboratory and field studies to ensure that steel bars were adequately bonded when impressed current cathodic protection was applied.  Bennett presented his study and findings at a NACE conference committee meeting in the early 1990s, but never published it, however, he did circulate an internal Eltech memo of the work.

In researching the literature, I became aware that no one else had published anything on this subject, but Jack’s findings were being used in the standards on cathodic protection of steel in concrete such as
BS EN ISO 12696.  I contacted Jack, who has now retired, and he, along with his former employers agreed that the memo should be published. 
I therefore transcribed it into a Structural Concrete Alliance Technical Note [6].    

The memo states that Bennett found the use of a Nilsson meter gave inaccurate measurement, indicating continuity where none existed.  This is fortuitous, as, using a high impedance Fluke multimeter he got more accurate measurements.  High impedance meters are always available on site when taking reference electrode potential measurements for investigation purposes and when installing cathodic protection systems.

It is interesting to note that Bennett found the most accurate method of determining continuity was to measure the DC potential difference between bars, which should be less than 1 mV.  A slightly less accurate method was to measure the (DC) resistance which should be less than 1 ohm.  In both cases, the leads should be reversed and the readings repeated.  In BS EN 12696, the resistance technique appears to be given priority over the potential technique, which is not the priority that Bennett recommended. I would always recommend using both techniques, especially is there is any doubt about continuity.

There has been discussion in standards about whether the criterion for potential difference or resistance should be higher or lower.  My reaction has always been that when anyone can offer hard data we should consider it, but until someone does so, then these are the criteria we should use.  It would be good to see someone repeat or improve on Bennett’s work. but until then it is what we have to go on to ensure we have electrical continuity in our reinforcement cages.

References

1. J. P. Broomfield, Corrosion of steel in Concrete, 2nd Edition, Taylor and Francis, 2007.

2.ASTM C876 (2015) Standard test method for corrosion potentials of uncoated reinforcing steel in concrete.

3. BS EN ISO 12696 (2016), Cathodic protection of steel in concrete.

4.BS EN 1504-1 (2016) Electrochemical realkalization and chloride extraction treatments for reinforced concrete Part 1 realkalization.

5.BS EN 1504-2 (2021) Electrochemical realkalization and chloride extraction treatments for reinforced concrete Part 2 Chloride Extraction.

6.J. P. Broomfield (2021) The measurement of electrical discontinuity for steel in concrete subject to cathodic protection and other electrochemical treatments.  Technical Note 29 Structural Concrete Alliance, Bordon, Surrey.

John Broomfield

Ask the Expert – Issue 164

Ask the Expert

Question:

What errors are most likely to occur when measuring dry film thicknesses on steel, and how can they be avoided.  PS

Answer:

Dry film thickness measuring probably causes the most conversation/arguments on site than anything else, this is normally born out of the absence of an inspector test plan or no conversation/agreements with client/contractor/inspector.

Errors made during dry film testing are due to several reasons, including due to taking measurements before the paint or paint system is hard dry.   A contractor will paint until the job for the day is done, and of course this will continue well into the afternoon, then the Inspector, or Supervisor will take a measurement with a dft gauge. If the paint is not ‘hard dry’, the probe will push into the coating giving an incorrect lower reading than may have been expected.  Before taking a dft reading, ensure the paint is hard dry by pushing a fingernail into the paint. If the fingernail leaves a depression, then the paint is not hard dry. If of course no depression is left, then the paint is hard dry.

However, the most common error is not calibrating the measuring device to the same blast profile as the uncoated steel. Often this is not possible, so alternative calibration methods need to be used, as described below.

(1) Measure the blast profile before application of the paint, and after applying the system allow to become hard, then measure the dry film thickness using a digital gauge (or other). Then subtract the blast profile to give the true dft of the paint system.  For example, if the steel surface has a typical profile after blasting of 50 microns, and the applied paint measures 300 microns, then then total dft is 250 microns (covering the peaks of the blast).

(2) Calibrate the dft gauge using a surface profile comparator to the expected surface profile, and then accept that the measured dft is the correct reading.

(3) Calibrate the gauge on a piece of smooth steel, then measure the dft of the paint, and subtract 50 microns as being the nominal blast profile.

Whatever method is used it must be agreed pre-contract and should be included in the inspection test plan. In the absence of a test plan, one should be created and accepted by all parties before painting commences, this prevents disagreements at a later stage.

Kevin Harold, Paintel Ltd

Answer:

Dry Film Thickness or (DFT) is probably the single most important measurement made during inspection, or quality control of a protective coating application. Even the most basic coating specification will inevitably require the DFT to be measured, which is considered to be the most important factor determining the durability and longevity of a coating system. The thickness of each coating layer in a system, and the total system DFT will have to be measured and recorded to show that the specified system will meet the desired durability.

There are many mistakes which can be, and are often, made when measuring DFTs.  Often its believed that it’s a case of simply putting a probe on a coated substrate and taking the measurement, and that’s where the numerous issues occur.

DFT is typically recorded with either a magnetic pull-off gauge (Banana gauge or Type 1) or an electro-magnetic constant pressure probe gauge (Type 2).  Both these types of gauges are non-destructive (will not damage the protective coating during the inspection) and are the most commonly used methods for measurement of film thickness of protective coatings.   

The Type I gauge works by recording the magnetic force needed to pull off the gauge from a ferrous substrate. Simply a barrier or a coating between the substrate and the gauge’s magnet reduces this magnetic attraction, which can then be measured i.e. the force required to pull the gauge magnet from the coated substrate is shown on the gauge as the film thickness of the coating material.

There are benefits in using a type 1 gauge, however there are often great challenges for an inspector with calibration, which has proved to cause major problems on projects. For example, determining the Base Metal Reading (BMR).   For accurate calibration of Type I gauges the standard SSPC PA2 specifies that after calibration using a NIST test standard, or equivalent standard DFT shim with traceable calibration, that a measurement of the blast profile should be taken in order to achieve an accurate DFT reading as possible. This is not 100% accurate and can affect the resulting DFT reading. This BMR measurement  is carried out on the blasted surface using the Type I gauge and which depicts an imaginary magnetic line in the blast profile This reading is always deducted from the final average reading of the DFT. This is typically done with a banana gauge or Type 1 DFT measuring gauge. Before use the BMR and NIST Standard deviation must be carried out and recorded, the inspector should always remember that the gauge should only be used on non-metallic coatings on a metallic or ferrous substrate.

However, the Type 1 gauge is ideal for use in environments where the use of electronic instruments is difficult, e.g. inflammable atmospheres in oil and gas production, and for underwater# dry film coating thickness inspection.

Type II gauges or the constant pressure probe gauge works by measuring changes in the magnetic flux within the probe of the gauge, the probe must remain in contact with the substrate during the reading or measuring process. The Inspector should be aware that the following may affect any readings taken.

• The magnet should be clean and free from surface contaminates such as iron or steel grits the inspector should also check the substrate is free of any contaminants which may adhere to the magnet prior and during DFT inspection.

• DFT readings should be taken only when the protective coating film is dry as if the coating is uncured or tacky the actual film will hold the magnet past the point when the magnet should have detached.

• The inspector should note that vibrations may cause the magnet to release prematurely resulting in a higher or inaccurate reading.

• Readings should generally not be taken within 25 mm or 1 inch of an edge as the magnetic fields in this area will interfere with the magnetic forces between the substrate and the gauge.

• Always ensure that you have a spare battery or a Type 1 Gauge for back up.

As with the Type 1 gauge, the Type 2 gauge must be calibrated with a traceable DFT shim on an uncoated area in order to account for the blast profile before any measurements are taken.

There are also other instruments used for DFT measurements, but which will damage the coating film. The most commonly used instruments are the Paint Inspection Gauges (PIG gauges) or Tooke gauge. These instruments are termed as destructive test methods due to the necessity to cut into the paint film to obtain the measurement.

A further issue with DFT measurements, and the one which causes the main issues on site is frequency of testing.  The specification should always state the requirements for frequency of DFT measurements and film thickness acceptance criteria, or at the very least specify a standard to which DFT measurements should be carried out in accordance with. The number of measurements that will be made is important to all parties involved in coating works. The contractor and inspector obviously need to be in sync with requirements for such an imperative measurement and not to confuse one another in the field.

Lee Wilson, Corrtech Ltd