Ask the Expert – Part 2

Question:

What is the best approach to detect and monitor CUI ? CL

Answer:

The most reliable method to detect and monitor CUI is a full strip of the insulation and visual inspection, although once CUI is detected with this method it is rarely monitored. The key disadvantage of this approach is the high cost and required resources associated with access, stripping, possible refurbishment of the coating, and reinstatement of the insulation. The need for a reliable screening technique to focus CUI inspection efforts has been recognised for many years. Various non-destructive techniques (NDT) are available to detect CUI directly without removing the insulation, such as real time radiography (RTR) and pulsed eddy current (PEC). However, the drawback of these techniques is the uncertainty around probability of detection (POD), despite significant technique improvements in recent years and development of technologies through joint industry projects such as those done by HOIS (Harwell Offshore Inspection Service). Possible presence of CUI can also be detected with indirect techniques which are based on detection of water or humidity in the insulation system. Techniques such as thermography, neutron & x-ray backscatter, and more recently various types of sensors are all capable of detecting water or humidity but similar to direct methods there is still uncertainty around the POD and questions about the reliability. Another drawback is that detecting water does not necessarily mean that CUI has occurred at the points where water is located. Much development work continues especially with sensors which may offer better monitoring capability including direct detection of corrosion. Improving CUI predictive capability through greater sharing of data and analysis can also help focus where to inspect, but the CUI still needs to be located and there are many instances of CUI “surprises” in the industry especially if 100% stripping of insulation is not done during service of the facility. It should also be recognised that it can take 15 to 20 years to fully validate CUI technology developments and therefore compromises will inevitably be sought. A complementary approach involving direct NDT, water detection, sensor monitoring and the application of better data analysis and CUI prediction is probably the optimal way forward to focus efforts with CUI inspection planning, but full strip and visual inspection remains the most reliable approach.

Steve Paterson, Arbeadie Consultants

Ask the Expert Part 1

Question:

“How do you know when the pot life of a 2-component paint has expired ? Can you extend pot life, if so, how?” PS

Answer:

The reaction or cure of a two-component paint or coating is initiated when the two parts are mixed together. The manufacturer will state a pot life at a given temperature on the product data sheet.

Generally speaking the reaction rate doubles for every 10 degrees C increase and halves for every 10 degrees C reduction in temperature, this can be used to estimate the pot life at different temperatures if this is not stated on the data sheet. The age of the product can affect the pot life, depending on the chemistry of the particular product this could produce a longer or shorter pot life. Furthermore, the type of pump, fluid friction and pressure in the pump also have an effect and therefore it is also good to know the signs of when the material is towards the end of it’s pot life.

There are other variables in material chemical composition and properties such as the viscosity, lubricity and level of fillers but generally speaking a sudden increase in blockages, viscosity, reduction in fan pattern and atomisation are a sign the material is past its best, also most reactions are exothermic therefore the product will start to get hot.

One method that can be used for extending pot life at higher temperatures is cooling the product, or cooling the pump. Care should be used when cooling the product as it could be below dew point and take on moisture during mixing and atomisation.

Some products have a pot life inhibitor available to increase pot life in hot climates, this is mixed into the product prior to adding the Part B and applicable to products cured by free radical polymerisation. Some products are also available with tropical or winter grade hardeners.

Any attempt to extend a pot life after mixing will affect the final cure and other properties of the material and could poison the reaction completely, for example mixing in additional solvent. Of course solvent should only be added when it is recommended by the manufacturer and only up to the maximum percentage stated.

Phillip Watkinson, Corrocoat

Ask the Expert

Question:

What are the advantages and limitations of impressed current CP compared to sacrificial anodes, and where would you use one opposed to the other? BK

Answer:

In order to help readers of Corrosion Management to understand the differences between impressed current and sacrificial anodes cathodic protection systems, let me to start with a brief definition of both systems, where they are installed, type of anodes, sources of energy, and finally indicate what their advantages and limitations are. In both applications, CP current flows from the anodes, through the electrolyte to the structure being protected.

Impressed current systems

The impressed current systems use an external source of energy to provide direct current for cathodic protection. Generally, they are used when large quantities of protective current are required, for bare structures, those with poor coatings, or when the resistivity of the electrolyte is over 5000 Ohm-cm. They are also used for most long
buried pipelines, irrespective of coating quality and for above ground storage tank bottoms, seawater intake systems, interiors of fresh water tanks, well casings and many ship hulls. They are used for some piers, jetties and offshore structures if power is available.

Types of impressed current anodes

Dimensionally Stable Anodes: Substrates of titanium and niobium with coatings of platinum and mixed metal oxides (MMO) of ruthenium and iridium. Presently MMO/Ti are most commonly used.

Ferrous Metals: iron-silicon-chromium, iron-silicon-chromium-molybdenum, iron with high silicon, cast iron, carbon steel, stainless steel. Presently Fe-Si, with Cr in chloride rich areas and Fe-Si are most commonly used. Anodes of magnetite (Fe3O4) are also used.

Lead and graphite-based materials have historically been used but the superior performance of the materials above has caused the cessation of their use. Coke breeze is widely used in conjunction with suitable anodes, in buried applications, to effectively decrease resistance and increase life.

Non-ferrous metals: aluminium and zinc are used in some very specialised applications and copper in anti-fouling systems.

Energy sources

Transformer Rectifiers: single-phase or three-phase, extensive range of input voltages (120, 220, 480V AC), cooled by air or oil, typically with silicon diode rectifiers; these deliver low voltage DC for the cathodic protection. They can be simple constant Voltage, or constant Current and or Potential Controlled. The second are used when the design needs constant level of current. The last when it is required to automatically adjust the output to maintain constant structure/electrolyte potential with respect to a permanent reference electrode. Mains electricity and transformer rectifier normally provide the lowest cost and highest reliability impressed current for CP.

Solar Energy: utilised in those locations where there is no commercial power source available. They require batteries to deliver CP power at night and poor weather when solar energy is not available.

Wind Energy: is used where there is no electric energy and the solar energy is limited. They require batteries to supply current when there are no winds.

Thermoelectric Generators: utilised as a low voltage DC supply in remote places where there is availability of hydrocarbon fuels (e.g. natural gas, methane, propane). They are high technology equipment and require periodic maintenance.

Galvanic anode CP systems

Galvanic anode systems deliver CP current due to the difference of the electrochemical potential between them and the structure. The anodic materials is more active in the electrochemical or galvanic series of metals than the structure material. Galvanic (or sacrificial) anodes are generally used in environments of low electrical resistivity. Typical applications are: offshore oil and gas platforms and pipelines along with offshore wind foundations, ports and harbour facilities. These are all quite high current applications Smaller current applications are those such as short sections of buried pipelines, internals of flooded vessels or structures like barrages, oil field production vessels, water knock outs, desalters and separators, water storage tanks.

Types of galvanic anodes and uses

Magnesium: Soils, typically with resistivity up to 10000 ohm-cm, typically pre-packaged with a backfill of gypsum (75%), bentonite
(20%) and sodium sulphate (5%). Can be used in ribbon form.

Zinc: environments with resistivity lower than 2000 ohm-cm. Cn be used in soils with backfill of gypsum (50%) and bentonite (50%). Deficient operation in electrolytes that contain bicarbonate, carbonates and nitrates. Limited to temperatures up to 60°C. Can be used in ribbon form.

Aluminium: The main use of aluminium alloy anodes is in seawater and marine sediments environments, such as offshore platforms and pipelines. Deficient operation in electrolytes of pH alkaline (>8); in closed compartments with no replenishment can cause significant reduction in pH and inadequate performance.

Cathodic Protection System

Advantages

Limitations

Impressed Current

Significant range of driving voltages and higher
and adjustable current outputs

Operation in extensive range of resistivity

Great variety of anodes with very low rates of consumption

Electronic control and monitoring can be advantageous and reduce inspection and maintenance costs. Often essential in severe fluctuating DC traction interference

Can be operated at constant current or constant potential adjustment

Reliable onshore and if properly maintained, on ships

Require external source of energy

More likely to generate stray current interference
to foreign structures than galvanic anode

Susceptible to deterioration by external conditions, particularly offshore

Require monitoring of potentials for safe operation to avoid over and under-protection

Offshore systems may have high inspection,
control and maintenance requirements

More complex and in some applications, less
reliable than galvanic anode systems

Electronic control and monitoring can cause additional complexity and lower reliability

Sacrificial Anodes

Robust, simple and reliable

Generally easy installation and few components

Low costs of installation and maintenance

Do not require external sources of energy

Generally cause limited interference or interference problems with other structures

Limited driving voltage

Low and limited current output from individual anodes

Life is a function of the anodic mass

Attacked in acid environments

Operation affected by the environment resistivity

CAPEX can be higher than impressed current systems, but, generally, OPEX is generally less

Question:

What is the impact of corrosion on the offshore renewable sector, and how is this being controlled? AN

Answer:

The world is depending more and more on clean renewable energy as opposed to that based on oil and gas, and the renewable sector is rapidly becoming one of the biggest energy sectors in the world, with wind farms breaking records for output and size. However, with these farms come many of the same corrosion and engineering challenges that have been faced by the oil and gas sector for many years. Corrosion is a major risk for offshore wind foundations, its effects could mean costly offshore retrofit work, resulting in the loss of energy generation, and expose operatives to additional health and safety risks. Corrosion protection is thus of vital importance to assure the integrity of offshore structures, to minimise exposure to these risks.

It is estimated that the cost of painting an offshore structure in a dedicated painting facility can be up to 25 percent less per square metre compared with coating onsite. In addition, costs brought about by repair work to a new coating system carried out onsite have been estimated by one coating manufacturer to cost up to 5 to 10 times more per square metre compared with repairs made in the shop. A report by TWI stated that a recent coating failure on a wind farm off the coast of Ireland cost over £2m to rectify, 20 times the cost of the original installation itself

Thus, it makes sense to complete the corrosion protection of any structure in a paint shop or facility straight after fabrication—including painting, inspection and any necessary repairs. A corrosion protection strategy should be an integral part of the production process, and an appropriate time frame allocated in order to successfully execute the painting programme prior to delivery. It’s a simple concept, in order to increase quality and reduce costs, owners must ensure the dedicated site team includes a corrosion control specialist during design, construction, and commissioning, in order to ensure that the work is carried out on time and to the required specification.

Most of the standards available for offshore corrosion protection of wind turbine towers have been used in the oil and gas sector industry for many years, including ISO 12944 and NORSOK M-501. However, it is often seen in the recruitment adverts for corrosion control and QA/QC personal, the requirements being specific to the renewable sector, many whom are not familiar with the oil and gas sector, which in turn has created its own issues and subsequent failures and delays to project execution.

There are a number of different wind tower structural configurations, and these can a have an impact on the protective coating system applied. Although the external corrosion at the splash zone and tidal areas has been of great concern to the industry, particularly when dealing with the stress and fatigue related parameters of the towers, this corrosion in general is well understood and very similar to the challenges observed across other offshore facilities. However, internally, in the closed compartments, the current guidelines and standards are inadequate, as with data from inspections and surveys becoming available, major Issues such as fatigue and stress issues, design and material selection, cathodic protection, need to be addressed.

Experiences with internal corrosion have shown that it is difficult in practice to completely seal compartments and render them airtight. If the closed-compartment structure is not properly sealed, direct ingress of air is certainly possible. One major certification society has noted that seawater and air (oxygen) ingress were detected in foundations that are as new as two years old, which increased the rate of corrosion and localised corrosion attack. After the commissioning of monopile foundations in many offshore wind farms, corrosion problems have been observed inside of the monopiles in the area located beneath the so-called ”air-tight deck”. The cause of this corrosion has been usually a failure of the subsea cable entrance seal which allows air (oxygen) to penetrate into the monopile. This is in complete contradiction to the assumption that the submerged internal area is a ”gas-free” area, with a low corrosion risk due to a limited presence of oxygen after initial oxygen depletion. There is also a risk of microbiologically influenced corrosion (MIC) in a closed-compartment foundation, with localised corrosion attack on the submerged surface and in the portions of the monopile buried in the upper region of the sediment. Alternating aerobic and anaerobic conditions may also favour bacteria growth, and the risk of MIC depends on the bacteria species and the environmental conditions present. Sulphur-reducing bacteria (SRB) are expected to be present, and if growth conditions are favourable, then sulphide production can occur. Differences in the state of the tide result in variation of the water level inside the pile, and this has led to micro-organism in the seawater, that do not require oxygen to survive, such as SRB. Some suppliers insist on placing cables inside the tower going through the pile and leaving the structure through a hole below the water known as the rat hole which is sealed. This seal has proven in many cases to be inadequate and again allows water ingress into the pile.

The offshore wind energy sector is facing major challenges and not fully addressing the corrosion issues, nor implementing strategic corrosion management systems from the design stage, due in part to the demand pressures for supply to meet the energy requirements.
Lee Wilson, Corrtech Ltd.

 

Ask the Expert

Ask the Expert

The question in this issue features solvent free epoxy coatings. Readers are reminded to send in their technical questions for possible inclusion in this column in future.

Question:
I wish to use a solvent free epoxy coating to lower the environmental impact of my maintenance painting project, however when I look at the products available there appears to be a wide range of volatile organic compound (VOC) content in such coatings. Why does a solvent free epoxy coating contain VOC , and what is the difference between a solvent free epoxy, and a 100% solids epoxy coating? PF

 

Answer:
A 100% solids epoxy coating contains no solvents, no VOC and retains the same level of thickness from the time they are applied to the time they dry. There is currently no clear universal definition of a Solvent Free Epoxy Coating. The generic name indicates that the epoxy coating should be “solvent free”, but when looking at these coatings in the market today, we see that that is not always the case. To be able to spray apply such a solvent free coating through single feed airless spray equipment, the viscosity needs to be low enough to get a good spray pattern without the need for thinning with solvents. A very common formulation approach for solvent free epoxies is to use low viscosity liquid Bisphenol A or Bisphenol A/F epoxies that have been modified with reactive diluents. The epoxy binder is cured with low viscosity polyamine or polyamide curing agents that can be supplied with 30% benzyl alcohol as a solvent to further lower viscosity, and which is compatible with the epoxy, and aids the cure. In many cases the viscosity needs further reduction to reach optimal application properties, so 10 weight % or more benzyl alcohol solvent can be added as a non-reactive epoxy resin diluent.

Without any scientific proof (that we are aware of) benzyl alcohol has been claimed to remain as a solid in epoxy coatings, but benzyl alcohol is an aromatic alcohol with a boiling point temperature of 205 C and should strictly speaking (in our opinion) be classed as a solvent, and contribute to the coating’s VOC [1] content. Some argue that due to benzyl alcohol’s high boiling point temperature most of it will not evaporate or diffuse out of the coating film. There is however a reason why over the last two decades we have seen solvent free epoxy coatings for potable water tanks move towards benzyl alcohol free formulations as it has been observed that over time the solvent diffuses out of the coating film giving taste and smell to the potable water [2,3]. The significantly lower practically determined volume solids, compared to the values calculated treating benzyl alcohol as a non-volatile, is a strong indication that it is in fact volatile and should be classified as a solvent.
The benzyl alcohol contents in the epoxy base and curing agent part of marine solvent free epoxy tank coatings taken from the coating manufacturers material safety data sheets, are shown in table 1.

Table 1. Benzyl alcohol (BA) content in some typical marine solvent free epoxy cargo and potable water tank coatings.

Table 1. Benzyl alcohol (BA) content in some typical marine solvent free epoxy cargo and potable water tank coatings.

From the table it is clear that not all paint manufacturers count benzyl alcohol as a solvent that increases VOC and lowers volume solids of the coating, so we get the unfortunate situation that solvent-free coatings that should have very close to 100% volume solids and VOC 0 g/l can vary anywhere between 95 – 100% solids, and 0 – 180 g/l in VOC. Considering that ultra-high solids epoxy coatings can have up to 97% VS and down to 50 g/l in VOC, a universal common definition of solvent-free epoxy needs to be made so that users can clearly distinguish between solvent free, ultra-high solids epoxy coatings, and 100% solids epoxy. As the main advantages of solvent free epoxy coatings are very low or no VOC emissions, the possibility to apply thick coating films with little or no film shrinkage and lower film formation stress.
Based on work we did more than a decade ago, we would like to propose the following universal definition for a solvent free epoxy coating to avoid confusion by users. Hopefully, this will start a discussion among relevant stakeholders to agree on a common clear and universal definition.

Michael Aamodt, Alan Guy and Raouf Kattan, Safinah Group

 

“A ‘solvent free epoxy’ coating can be defined as an epoxy paint where all of the non-reactive components of the formulation have an initial boiling point greater than 250 C at an atmospheric pressure of 101.3kPa. Benzyl Alcohol added to epoxy coatings should be counted as a volatile since it is not reactive and falls within the definition of a solvent according to EU Paint Directive 2004/42/CE. Benzyl alcohol will also lower the practical volume solids compared to that calculated and often stated on data sheets, when assuming it is non-volatile. At the same time its inclusion increases the volatile organic compound (VOC) content of the coating.”

References
1. “Directive 2004/42/CE of the European Parliament and of the Council of 21 April 2004 on the limitation of emissions of volatile organic compounds due to the use of organic solvents in certain paints and varnishes and vehicle refinishing products and amending Directive 1999/13/EC”. Official Journal L 143, 30/04/2004 P. 0087 – 0096.
2. J. Romero et al. “Characterization of Paint Samples Used in Drinking Water Reservoirs: Identification of Endocrine Disruptor Compounds”. Journal of Chromatographic Science, Vol. 40, April 2002.
3. Aamodt, M., “Eco friendly coatings for potable water tanks offshore”, Offshore Marine Technology, 1st Quarter 2010, 20-21.

Ask the Expert

Ask the Expert

In this issue the questions relate to monitoring of CP on pipelines and what causes amine blush on epoxy coatings. Readers are reminded to send in their technical questions for possible inclusion in the column in future.

Question:
I maintain a buried pipeline in an environmentally sensitive area and I wish to follow best practice in monitoring the CP system on it. I am thinking of fitting remote monitoring but I am concerned how accurate and reliable any reference electrodes that I use with a data logging system will be. Related to this I do not want to excavate to install the reference electrode to pipe depth, can I bury the reference electrode just below the surface near the existing Test Point? BK

Answer:
The practice you describe is one that is widely followed, for example in GRTgaz France on their high- pressure gas transmission system they use remote monitoring equipment from Italy and fixed reference electrodes often buried close to the surface under open bottomed surface boxes to aid their location and replacement. National Grid in the UK use remote monitoring extensively. However, there are a number of issues for you to consider:
1. Fixed reference electrodes can be significantly unreliable and their electrode potential can drift significantly from what you and the manufacturer may expect. This may be particularly so with electrodes in soils with significant groundwater movement. It is recommended that all fixed reference electrodes are supported with a method such as a UPVC tube from ground level to electrode level to permit a calibrated, portable reference electrode, likely a Cu/CuSO4 to be deployed close to the fixed electrode and the drift assessed. Depending upon how important the accuracy is, this should be done frequently.
2. Placing electrodes remote from the pipe will introduce errors in measurement, more in high electrical resistivity soils than in low, this is due to IR errors due to CP current flowing in the soil. The errors may be low with the electrode directly over the pipe and if your pipe coating quality Is high.
3. You might also consider deploying a steel ‘coupon’ that most remote logging systems will permit to be switched ‘OFF’ for Instant OFF measurements that should be more accurate in respect of IR errors in the soil. But if your reference electrode is in error these data will also be in error.
4. Large, simple, old fashioned porous pot Cu/CuSO4 reference electrodes are pretty reliable if properly constructed but there may be concerns regarding soil contamination with CuSO4. If you use these with coupons, the coupon should be remote (upstream of downstream along the pipe, not laterally spaced from the pipe) from the Cu/CuSO4 electrode to prevent CuSO4 leaching into the soil and plating out on the coupon. If this happens all the measured data will be wrong.
5. In France they consider that the values they measure in the way above to be accurate only to 50-70mV. So be cautious with data close to under or over-protection values if the data come from this sort of installation. B.Wyatt, Corrosion Control Ltd
In GRTgaz France, we have installed and used Remote Monitoring Systems (RMS) with fixed reference electrodes for about 8 years. They are installed in open bottomed surface boxes to be regularly compared to a portable reference electrode (during detailed and comprehensive assessment of CP by a CP operator in the field). As they are used for general assessment of CP, the requirement for their accuracy is lower than that for portable reference electrodes used in the field for detailed and comprehensive assessment of CP ±100 mV for a fixed reference electrode to be compared to ±20 mV for a portable reference electrode. To facilitate the evaluation of the accuracy of fixed reference electrode, GRTgaz France decided to install them in the open bottomed surface boxes as it is then easy to minimise the gap between both electrodes (fixed buried and portable) and to change the fixed reference electrode when required (which is very seldom, as we have had good performance from our reference electrodes!). Sylvain Fontaine, Cathodic Protection Expert, GRTgaz, Compiègne, France

Question:
What causes amine blush on epoxy coatings? PS

Answer:
Amine blush is a combination of three unwanted reactions between amines and moisture/carbon dioxide which lead to the formation of amine hydrates (with water), ammonium carbamates (with carbon dioxide) or carbonates (with carbonic acid). It is the latter of these which presents the biggest problem as the reaction is irreversible and leads to surface defects which are difficult to remove (carbonation). In epoxy coating systems this will normally be at the surface/air interface as a result of the amines in the curing agent. Since carbonation is essentially an acid/base reaction it is kinetically favoured over the amine/epoxy reaction which we would prefer. This is particularly problematic in application conditions of low temperature and high humidity where the amine/epoxy reaction is retarded even further, and we have high levels of carbonic acid.

Figure 1. Reactions of isophorone diamine with H2O and CO2.

Figure 1. Reactions of isophorone diamine with H2O and CO2.

It has often been suggested that the way to resolve this would be to make the amine-epoxy reaction faster, but using more basic amines simply leads to more carbonation as they will more readily produce blushing via the acid/base interaction. It is interesting to note that in the past when the use of aromatic amine curing agents was more common there was no issue with blushing when using these products because aromatic amines are not basic. Of course, these products are now considered as toxic and as a result are no longer allowed in many parts of the world.

We can see from this that using less basic amines should therefore lead to improved blushing resistance, but they will also produce slow hardeners with long drying times. The question then becomes, how do we produce hardeners which will give the best combination of drying times and resistance to blushing? This is particularly relevant for solvent free systems where we have no drying advantage from the use of solid binders. Curing agent manufacturers have over time developed curing agents with improved resistance to blushing using various formulating methods. For example, forming amine adducts will improve the performance against bushing because the adduction process will remove some of the more basic amine functionality in the curing agent which is often responsible for blushing. It will also improve the compatibility of the amine with the resin thus reducing migration of free amine to the surface of the coating. Advances in curing agent development mean that today the best performing hardeners for blushing resistance in topcoats are based on formulated adducts of one or more amines.

Of course, epoxy resin and curing agent manufacturers can develop and test their resins and hardeners in combination as clear coatings, but the final paint will be formulated by coatings manufacturers where the fillers and additives used will also have an effect on the carbonation resistance of the end product. Even with the recent advances in curing agent performance, the end result will still depend on correct mixing and application of epoxy systems on site ensuring that the conditions in which the coating is applied meet with the manufacturers recommendations.
Stuart Darwen, CTP Advanced Materials GmbH, Germany

Ask the Expert

Ask the Expert

The questions in this issue relate to painting galvanized steel and predicting CO2 corrosion in oil & gas upsteam operations.

Question:
How do you prepare galvanized steel before it is painted with an epoxy? PS
Answer:
Painting galvanized steel is quite simple as long as the correct steps are used. There are basically four alternative methods to prepare this surface for painting, T-Wash, etch priming, sweep blasting, and weathering. Ideally the surface should be treated immediately after galvanising, but if this is not possible then it can still be carried out later, although the surface must be thoroughly cleaned to remove all contaminants.

T-Wash is a phosphoric acid solution with a small amount of copper carbonate which reacts with the zinc surface and turns it black. An even black colouration confirms that the whole surface is free from grease, and etched ready for painting. The solution must be allowed to dry fully and should be painted as soon as possible, and withing 4 weeks. It should not be used on galvanizing that has been allowed to weather however. There are also other equivalent proprietary products.

Etch primers are similar to T Wash, in that they etch the surface ready for painting, however they have a major disadvantage over T-Wash in that there is no colour change of the surface, and there is thus no indication that the whole surface has been treated. They are however suitable for use on weathered steel.

Sweep blasting at pressures up to 40 psi can roughen the galvanised surface sufficiently to provide a key for the subsequent paint system without removing too much of the zinc surface. Only a fine copper slag, and not the more common angular iron grit should be used, and care needs to be taken to determine the stand off distance and angle of blast to ensure the optimum surface is obtained. Sweep blasting is also often used in conjunction with a chemical pre-treatment.

Exposing a galvanized surface to the environment is another method for preparing it for painting. This should be for a minimum of 6 months, after which the surface is cleaned with a stiff brush to remove the loosely adhering material, leaving a bright zinc metal surface. The surface is then thoroughly washed and allowed to dry fully before being painted.
In all cases, the paint system should be applied according to manufacturers’ recommendations.

It should also be mentioned, that there are some paints which have been specifically formulated to be applied directly to the galvanised surface, and thus no pre-treatment stage is necessary. BG

Question:
How accurately can you predict CO2 corrosion in upstream operations? BK
Answer:
To do full justice to the question really requires writing a major article and even a book. The European Federation of Corrosion (EFC) publication #23, CO2 Corrosion in Oil and Gas Production Design Considerations is an excellent reference, if a little dated now having been published in 1997. Reading through more recent papers on the subject presented at the annual NACE International Corrosion Conferences can provide an excellent source of current thinking and practice.

Nevertheless, it is useful to address the question in two steps. For a given set of conditions, firstly what is the likelihood of CO2 corrosion occurring; and secondly, if likely, in what form and rate will it occur.
While predictive models have become the immediate go-to especially as the computing power and sophistication of laptops, tablets and increasingly smart phones continues to grow exponentially, together with ready access to the internet, it is useful to take a breath to reflect on what simple rules generally are worth having to hand. Concerning the likelihood of CO2 corrosion occurring, the following rule of thumb is worthy of note:

PCO2 < 7 psi (0.5 bar) Corrosion Unlikely
7 psi (0.5 bar) < PCO2 < 30 psi (2 bar) Corrosion Possible
PCO2 > 30 psi (2 bar) Corrosion

An important additional qualification to the above rule is how the following partial pressure ratios, to take account of the presence of H2S if also encountered, effects the resulting corrosion process:

CO2/H2S > 500 CO2 Dominates
500 > CO2/H2S > 20 Mixed CO2/H2S
0 > CO2/H2S > 0.05 H2S Dominates

From a detailed system design and operating standpoint, and for developing a fit-for-purpose corrosion / integrity management strategy, clearly the above rules provide limited hard engineering insight and basis to work from. However, they provide a quick and simple appreciation of the situation ahead of launching into modelling – the latter is a necessary requirement regardless, but not without its challenges and limitation.

There is no one industry recognised, or accepted standard CO2 corrosion model. Over the years there has been a steady growth in the number models in use, in part driven by several of the major oil & gas companies producing their own in-house developed models. All the models are principally directed at predicting CO2 corrosion of carbon and low alloy steels.

It is also worth recognising here the work over many years of de Waard et al (Shell) for their significant openly published contribution to the understanding and key requirements of building a robust CO2 corrosion model and its sound application. In fact, many of the at least 17 models readily found via an internet / published technical papers search owe much to the leading fundamental and practical insight resulting from the work of de Waard et al. It should be noted that most models are empirical in origin based on lab and/or field data. The most extensive and widely recognised theoretically based CO2 corrosion model, a product of a Joint Industry Project (JIP) funded programme at the Ohio University, forms an integral part of Ohio’s Multicorp corrosion prediction software covering almost all key aspects of internal corrosion of mild steel oil and gas pipelines. If not a member of the Ohio JIP, access to the Mulitcorp software is subject to a user charge.

Ready and free access to the models may be limited but a good starting point readily accessible on the internet is: CO2 Corrosion Rate Calculation Model, NORSOK Standard M-506 Rev 2, June 2005. There are commercial models available at a cost, such as the Wood Group’s Electronic Corrosion Engineer ECETM ® tool designed to assist corrosion engineers through the quantitative estimation of corrosion rates, including CO2 corrosion modelling and prediction, and selection of corrosion-resistant materials; and Broadsword Engineering’s proprietary web-based CO2 corrosion model enpICDATM as part of the technical service they offer.

A comparative review of many of the models was presented in Paper No. 10371, NACE Corrosion Conference 2010, San Antonio, CO2 Corrosion Models for Oil and Gas Production Systems. Whereas Paper No. 05552, NACE Corrosion Conference 2005, Houston, entitled A Prophetic CO2 Corrosion Tool – But when is it to be believed? provides additional related background reading resulting from BP’s development of their model Cassandra.

All the models have their strengths and weakness that will to varying degrees be dependent on the specific application. It would be inappropriate here to advocate use of any one model above the others.

  • Understanding the current condition and operating details of a system is equally a critically important step to making a sound choice and subsequent application of model. Some key points to consider are:
  • Understanding the origin of the model to be used, and how it addresses the key factors that will determine the predicted corrosion rate
  • Range of CO2 partial pressure and temperature applicable
  • How it computes pH and range of applicability
  • Flow regime and liquid velocity noting that CO2 corrosion is a mass transfer controlled reaction
  • Presence of potential corrosion hot spots – e.g. bends, dead-legs, and surface flow disturbances such as pre-existing corrosion, weld beads – can profoundly affect the form of attack (general versus localised metal loss)
  • Surface fouling/shielding due wax, scale, solids drop-out – can profoundly affect the form of attack (general versus localised metal loss)
  • Effect of liquid hydrocarbon phase wetting
  • FeCO3 protective scale formation, its nature and stability – will profoundly affect the form of attack (general versus localised metal loss)

Additionally

  • Presence of H2S – often results in very low general corrosion rates but increased risk of pitting and few models are strong at predicting the joint corrosive action and rate in the presence of CO2 + H2S
  • Presence of dissolved volatile organic acids (e.g. acetic acid/acetate) – can significantly increase the actual corrosion rate
  • Risk of top-of-line corrosion (usually wet gas systems but also may effect multiphase lines under stratified flow with a gas space) where water condensation rate is a key factor; also the risk is exacerbated by the presence of volatile organic acids and H2S
  • Presence of solids leading to erosion-corrosion – usually results in a synergistic effect on resulting metal loss rate for cabon/low alloy steels that may result in localised attack

Having given due consideration and attention to the above in selecting a model, which can be further helped by looking for field analogues to draw comparisons with, the predicted rates will generally be acceptable for design purposes – e.g. if carbon steel can be used with or without use of a corrosion inhibitor supported by a specified corrosion allowance as part of the required nominal pipewall thickness. Also, predicted rates can be used in support of conducting corrosion risk-based assessments as part of developing a fit-for-purpose corrosion management strategy. If the form of attack is likely to be localised from, for example, consideration of the above points or from inspection data, it is common to apply an escalation factor – typically a 2 or 3 multiplier – to the predicted base corrosion rate. Operating company guidance documents and practices may detail specific requirements for applying escalation factors. It is also important to recognise that poor operation of corrosion control measures such inhibitor treatment and system cleanliness can adversely affect the underlying value of originally predicted corrosion rates.

Effectively managing corrosion solely based on predicted corrosion rates once a system comes into operation is not recommended no matter how good a model is hailed to be. Modelling should be treated as complementary to having in place a proactive and robust risk-based corrosion monitoring and inspection programme that also provides a feedback loop to enable further improvement of a model.
Finally, can any of the models truly predict mm/y corrosion rates to two or even one decimal place? They may display computed rates to such a level, but this could well be more a function of how the software is written than the actual inherent accuracy of the model. Caution should be exercise when using and quoting model-generated predicted corrosion rates to such decimal place accuracy!
Don Harrop FICorr(Hon) FEFC(Hon), CorroDon Consulting Ltd.

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