Ask the Expert – Part 1

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This month, the questions being answered by our corrosion technology experts relate to acid storage tank linings and the deployment of non-intrusive corrosion monitoring devises for pipelines and process pipework.

Question:
What is the best lining for a hydrochloric acid storage tank? DD

Answer:
Equipment fabricators looking to offer corrosion protection for the storage of hydrochloric acid have a number of materials at their disposal. Whatever method is selected this should be able to create a safe environment, without compromising the tank integrity as well as maintain continuous operation and avoid adverse effects on the cargo itself.

At a very basic level solutions can be divided into inorganic and organic. The inorganic solutions may include; metallic solutions, such as alloys which are capable of resisting a wide range of acids including hydrochloric, and ceramic solutions, such as bricks /tiles, often used in conjunction with an organic solution such as vinyl esters or furans in the joints and behind the brick system. The organic solutions may include; thermoplastics which are bonded or physically adhering to the metal substrate, and reactive thermoset types which cross-link to firm an acid resistant coating barrier.

Whilst resin coating types are widely used in acid secondary containment areas, their use in tanks and vessels is considered a higher risk, however they remain attractive due to the relatively low cost of installation when compared to metallic or ceramic options. Phenolic or Novolac epoxies can provide suitable resistance to hydrochloric acid (though they are less resistant to more oxidising acid species) provided that they are formulated with a suitable hardener, with amine hardeners generally being more resistant than amides, though still susceptible to acid hydrolysis and subsequent degradation.

Vinyl esters have high resistance towards both oxidising and non-oxidising acids and offer a suitable solution for hydrochloric acid providing both good chemical resistance and ease of application. Their good overall resistance arises from the extensive presence of aromatic groups within the resin and the presence of methyl groups which have the effect of stabilising the ester linkage.

However, colour change of the coating material is a commonly found phenomenon with acid materials, and can result in adverse effects on the acid cargo itself (colour tainting) which may not be acceptable where stringent quality checks or high purity requirements are to be found. SD

Consideration of all the above factors will greatly influence successful applications/outcomes in this growing area of the CM equipment market. ST
Readers can submit generic (not project specific) questions for possible inclusion in this column. Please email the editor at, brianpce@aol.com

Fellow’s Corner

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The second article in this series from ICorr Fellows who have made a significant contribution in the field of corrosion science is by Don Harrop, Past President and Honorary Fellow of ICorr and the European Federation of Corrosion (EFC).

Corrosion Inhibitors in Upstream Oil and Gas Production

The use of corrosion inhibitors to mitigate the threat of internal corrosion affecting the design and operation of upstream oil and gas production infrastructure and facilities has proved to be a successful, resilient, flexible and cost-effective means of managing that threat over the past 60+ years.

A corrosion inhibition system generally requires relatively low capital outlay but carries a continuous whole life operating cost associated with ongoing cost of chemical, deployment and injection system management and associated maintenance, and supporting corrosion monitoring and inspection. Viewed on an NPV (net present value) basis, usually makes the use of Carbon and Low Alloy Steels (CLASs) together the most economically attractive option at the design stage of project – the base case consideration, a position unlikely to change in the future.

The history of the use of corrosion inhibitors has not been without it troubles, certainly in the early years when going through a learning curve of sound fundamental understanding of how they function versus meeting user demand. However, issues should they arise are now generally associated with insufficient or poor attention to managing inhibitor application and not per se inhibitor performance. Application is not just about the technology and method but how it is then consistently managed: it is a “cradle to grave” commitment and certainly not a “fit and forget” option.

The benefits of chemical corrosion inhibition can be summarized as:
Cost effective – can be sensitive to how the economics are calculated but generally it is the most capex efficient option.
Extend use of materials with established and favourable engineering properties – primarily talking about use of CLASs.
Flexible response – can be adjusted to meet changing operating conditions.
Retrofit treatment – response to unexpected increase in system corrosivity, a change in service conditions and/or life extension.
Assurance – where there is limited access/opportunity for inspection and/or corrosion monitoring
Can be applied to sweet (H2S free) and sour (H2S containing) systems, but the presence of even very low levels of oxygen (ppb level) can adversely affect performance of most inhibitor species, as can high temperatures (>~150 C).

What are they?

Commercially supplied corrosion inhibitors are formulated products. Typically, they contain 10% to 25% active inhibitor species – N, S O or P functional long chain organic compounds. A product’s primary constituent is the carrier solvent which is key to effective inhibitor deployment in a system. The formulation is a critical element affecting efficacy of performance versus specific application, and why there is not, at least so far, a “silver bullet” corrosion inhibitor suitable for all applications. Consequently, undertaking appropriate testing/screening of products is an important precursor to making a final choice for field application. Other formulation considerations to note are: low toxicity to humans and compliance with environmental legislation (e.g. OSPAR regulations in Europe), high flash point for reduced hazard when handling, temperature stable for storage in hot (60 C) and cold (-40 C) climates, non-corrosive to metals used for storage and application of the neat product – may require the use of stainless steel lines and internally lined storage vessels, compatible with elastomers that are used in the injection system – does not cause excessive swelling, cracking or hardness changes, and non-foaming and non- emulsifying to treated fluids.

Strict adherence to a definition of a formulated inhibitor product being truly or exclusively soluble verses dispersible when considering application can be a grey area and care needs to be exercised. A formulated inhibitor will partition to a varying degree between the liquid phases present – viz. oil and water – and the ratio thereof will influence the actual concentration of inhibitor present in the aqueous phase even if an inhibitor product is designated as water soluble. Produced product solvent, temperature, pressure and flow conditions will also affect partitioning behaviour.

Selection and application

The operating conditions and constraints under which an inhibitor will be required to work must be understood and defined, not least because:
They will determine the methodology and scope of the test programme required for sound inhibitor selection.
They will determine the criticality and order of importance of factors affecting performance – e.g. if compatibility with another production chemical(s) is likely to be an issue, then it needs to be decided which one can a compromise on performance be accepted if unable to find a fully compatible optimum solution.
If the operating system to be treated has already experienced a level of corrosion damage this can be more challenging to manage to an acceptable level of inhibition.
Flow regime will influence the effectiveness of deployment in the field and influence the location of potential corrosion hot spots – e.g. sharp bends; dead legs.
Poor system cleanliness can be detrimental to inhibitor performance – e.g. build-up of solids, presence of wax or scale.

In recent years much effort has been directed at the development of test methods for studying and evaluating corrosion inhibitor performance. This has resulted in increased sophistication, especially when combined with use of ex situ and in situ surface analysis techniques, while being manageable and not excessively expensive to establish and run in a conventional laboratory environment. Good background reading and reference can be found in: EFC Publication #39 – The Use of Corrosion Inhibitors for Oil and Gas Production; ASTM G-170-06, 2012 – Standard Guide for Evaluating and Qualifying Oilfield & Refinery Corrosion Inhibitors in the Laboratory; NACE International Publication 1D196, Item No. 24192, 1996 – Laboratory Test Methods for Evaluating Oilfield Corrosion Inhibitors: Technical Committee Report, Task Group T-1D-34; UK Health & Safety Executive, Research Report RR1023, 2014 – Reliable Corrosion Inhibition in the Oil and Gas Industry.

Whether one or several test methods will be needed to generate data suitable for making a final selection for field deployment will depend on the complexity of the field conditions. For field conditions that are particularly complex, and the infrastructure/facilities are of high criticality, then it may be deemed necessary to conduct final inhibitor testing/selection using a large diameter flow loop able to simulate multiphase flow. There are only a limited number of such facilities available; for example, in the USA at Ohio University and the University of Tulsa, and in Norway at the Institutt for Energiteknikk (IFE).

Inhibitor performance is commonly expressed and measured in terms of efficiency – the percentage amount an inhibitor can reduce the uninhibited corrosion rate when present at a given concentration, usually the optimum concentration to achieve maximum efficiency. (NB. The uninhibited corrosion rate is often that measured in the lab or predicted using a corrosion model as actual field measurement may not be possible or desirable!) Given the organic structure and molecular size of inhibitor molecules, inhibitor efficiency typically is in the range 95% to 99% due to the spatial limitation of how well they can closely pack by adsorption on a steel surface to form a protective monolayer film. However, it is a common expectation at the design stage that an inhibited corrosion rate of 0.1mm/y to ≤0.5mm/y is consistently achievable which in turn will drive the monitored inhibited corrosion rate KPI throughout field operating life. This residual inhibited corrosion rate must be safely accommodated as a corrosion allowance within wall thickness for a given design life or required remaining field life.

The most effective and resilient and directly manageable method of inhibitor application is by continuous injection. However, underdosing and/or extended interrupted injection (>24hr) can adversely affect inhibitor film persistency/coverage that may result in localised corrosion or complete loss of protection.

In conclusion

It is perhaps not unreasonable to claim that the advent of oilfield corrosion inhibitors back in the 1950’s and their subsequent development has resulted in a significant enabling technology for the cost-effective development and successful growth of oil and gas production. Looking back, some may even claim inhibitors to be ‘a game changer’ technology! Going forward, with new projects exploiting reservoirs with fluids of increasing complexity and more aggressive environments, consistently achieving high inhibitor efficiency of performance and application will be paramount to economic project delivery and integrity risk management.

Standards Update

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ISO

The following documents have obtained substantial support within the appropriate ISO technical committees during the past two months and have been submitted to the ISO member bodies for voting, or formal approval.

ISO/DIS 8407 Corrosion of metals and alloys — Removal of corrosion products from corrosion test specimens (Revision of 2009 standard)
ISO/FDIS 8502-6 Preparation of steel substrates before application of paints and related products — Tests for the assessment of surface cleanliness — Part 6: Extraction of water soluble contaminants for analysis (Bresle method). (Revision of 2006 standard)
ISO/DIS 11127-8 Preparation of steel substrates before application of paints and related products — Test methods for on-metallic blast-cleaning abrasives — Part 8: Field determination of water-soluble chlorides
ISO/DIS 14571 Metallic coatings on nonmetallic basis materials — Measurement of coating thickness — Microresistivity method
ISO/FDIS 11844-1 Corrosion of metals and alloys — Classification of low corrosivity of indoor atmospheres — Part 1: Determination and estimation of indoor corrosivity (Revision of 2006 standard)
ISO/FDIS 11844-2 Corrosion of metals and alloys — Classification of low corrosivity of indoor atmospheres — Part 2: Determination of corrosion attack in indoor atmospheres (Revision of 2005 standard)
ISO/PRF 11845 Corrosion of metals and alloys — General principles for corrosion testing (Revision of 1995 standard)
ISO/FDIS 21062.2 Corrosion of metals and alloys — Determination of the corrosion rates of embedded steel reinforcement in concrete exposed to simulated marine environments
ISO 218093:2016/FDAmd Petroleum and natural gas industries — External coatings for buried or submerged pipelines used in pipeline transportation systems — Part 3: Field joint coatings — Amendment 1: Introduction of mesh-backed coating systems
ISO/DIS 22848 Test method for measuring stress corrosion crack growth rate of steels and alloys under static-load condition in high temperature water
ISO/DIS 23123 Corrosion control engineering life cycle—General requirements
ISO/DIS 23221 General requirements for pipeline corrosion control engineering life cycle
ISO/DIS 23222 Corrosion control engineering life cycle — Risk assessment
ISO/DIS 23449 Corrosion of metals and alloys — Multielectrode arrays for corrosion measurement
New International standards published during the last two months.
ISO 8044:2020 Corrosion of metals and alloys — Vocabulary
ISO 11844-3:2020 Corrosion of metals and alloys — Classification of low corrosivity of indoor atmospheres — Part 3: Measurement of environmental parameters affecting indoor corrosivity
ISO 15184:2020 Paints and varnishes — Determination of film hardness by pencil test
ISO 18086:2019 Corrosion of metals and alloys — Determination of AC corrosion — Protection criteria
ISO 22426:2020 Assessment of the effectiveness of cathodic protection based on coupon measurements

CEN

Standards published within the last two months.

EN 12390-12:2020 Testing hardened concrete – Part 12: Determination of the carbonation resistance of concrete – Accelerated carbonation method
This is a method for evaluating the carbonation resistance of concrete using test conditions that accelerate the rate of carbonation. After a period of preconditioning, the test is carried out undercontrolled exposure conditions using an increased level of carbon dioxide. This procedure is not a method for the determination of carbonation depths in existing concrete structures.

The following standard has been up-dated.
BS EN 17243:2020 Cathodic protection of internal surfaces of metallic tanks, structures, equipment, and piping containing seawater

Hempel coatings protect ISG containers

Hempel coatings protect ISG containers

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Hempel has announced that in just eight years it has painted 20,000 mining containers for Intermodal Solutions Group (ISG). The milestone 20,000th coating was completed in January 2020, and during this eight-year partnership more than 1.5 million litres of paint has been used to protect the containers against the highly abrasive and corrosive materials they carry, as well as the external environment.

ISG’s patented maritime and mining containers are unique, with a patented tippler operating system that rotates and tips the container to empty out the material being carried. This means they generally only need to be loaded and unloaded once to transport copper/nickel concentrate, iron ore, minerals, and other commodities from source to ship. Previously, material was loaded and unloaded several times during transit to the final destination.

The Interior paint solutions used included, Hempadur Multi-Strength 45751 and Hempadur Conterior 47751, both self-priming, high-solid, epoxy coatings, which cure to a highly abrasion and corrosion resistant coating. Externally, the traditional three-coat system consisting of Hempatex Hi-Build 46410, a high-build acrylic topcoat was used to provide resistance to saltwater, splashes of aliphatic hydrocarbons, animal and vegetable oils, together with Hempadur Primer 1530C, an epoxy mid-coat containing zinc phosphate as corrosion inhibiting pigment, and Hempadur Zinc 1536C, a zinc-rich epoxy primer that cures to a hard wearing and highly weather-resistant coating, concluded the company.

Introducing Cathodic Protection – Electrochemical Corrosion

Introducing Cathodic Protection – Electrochemical Corrosion

Blogs, Cathodic Protection Blog

Corrosion and electrochemistry from Davy to today

Cathodic protection is a highly effective method of preventing corrosion, and is used in multiple industries and environments. Its history in corrosion science really begins when Sir Humphry Davy first discovered the cathodic protection principles and applied them to electrochemical corrosion.

Davy’s experiments led to a better understanding of electrochemical corrosion and the first use of cathodic protection in 1824, when Davy successfully protected a British Navy ship’s copper sheathing from corrosion in seawater by using iron anodes.

In this article, we examine the process of electrochemical corrosion as an introduction to cathodic protection.

What is electrochemical corrosion?

Electrochemical corrosion is a process in which current flows between the cathodic and anodic areas on metallic surfaces, resulting in corrosion. There are always multiple elements in this process:

  • A host metal or metals exposed in an electrolyte.
  • An electrolyte is a medium that can conduct electricity by movement of ions (for example, saltwater, soil, or the pore water in concrete)
  • A metallic path between the exposed metal surfaces. Examples of this include:
    • A buried steel pipeline, accidentally connected to a copper earthing system in a classical ‘galvanic couple’ (the steel being anodic to the copper)
    • A buried or immersed steel pipeline or structure on which ‘anodic’ and ‘cathodic’ areas naturally establish due to variance in either the steel composition/metallurgy or within the electrolyte

Corrosion initiates on the metal/electrolyte interface and, at these anodic areas, low voltage direct current (DC) flows off the anodic metal into the electrolyte. Charged ions are released into the electrolyte and electrons are released into the metal. By convention, DC flow is opposite to electron flow.

The simple electrochemical circuit is:

  • Within the electrolyte (that is in the soil, the sea or river water, or the pore water within concrete) DC flows OFF the corroding anodic areas.
  • This must complete the electrical circuit, so it flows in the electrolyte and discharges on the non-corroding cathodic areas. The DC flows in the metallic circuit electronically, by electron movement. In the electrolyte it is via ionic movement, termed ‘ionic conduction’. The cathodic areas, receiving current flow from the electrolyte, do not corrode.

The electrochemist, rather than the engineer, will describe precisely the same process as the anodic area losing ions to the electrolyte (metal loss) and electrons to the metal (electron flow); the process is the same, it just that by convention the directions of electron and ion flow are opposite to the DC current flow.

In electrochemical corrosion, the magnitude of current flow is directly proportional to the rate of corrosion: approximately 10kg of steel is consumed by 1 ampere DC passing off a steel surface for one year.

How does cathodic protection help prevent corrosion?

Depending on whether it is described by an electrochemist or an engineer, cathodic protection might be described as:

  • Replacing the lost electrons from an external source, thus changing an anodic area into a cathodic area and preventing corrosion (electrochemist)
  • Providing cathodic protection current to all areas of the metallic surface within the electrolyte, sufficient to make all surfaces cathodic (engineer)

Though different descriptions, these are the same process.

Where is cathodic protection used?

Cathodic protection is used around the world to protect against corrosion, especially in aggressive environments such as soils, waters, and chloride contaminated concrete. Applications include:

  • Buried and immersed storage tanks – external surfaces of bases of above ground storage tanks with corrosive foundations; inside crude oil storage tanks with highly saline ‘water bottoms’; inside storage tanks for seawater or raw water
  • Ships’ hulls’ externals and internally in seawater-filled ballast tanks and cooling water systems
  • Offshore oil rigs, platforms, and subsea completions
  • Offshore wind foundations and tidal generators
  • Pipelines – buried and immersed – both onshore and offshore
  • Well casings
  • Flood defences and lock gates
  • Reinforcement in concrete

Cathodic protection is a specialisation

Though used extensively, cathodic protection is highly specialised. To be successful it requires a combination of the application of corrosion science, electrochemistry, electrical engineering, metallurgy, and often structural and mechanical engineering.

There are effective Standards (BS ENs and BS EN ISOs) for a wide range of CP applications in different environments for different types of structures. They all have one thing in common: all make clear that CP design must be undertaken by CP specialists with a documented and appropriate level of competence.

The standards make it clear that all work associated with cathodic protection (such as design, installation, testing, commissioning, performance assessment, and maintenance) should be undertaken by personnel with appropriate training, experience and competence.

How do you become a cathodic protection specialist?

Despite the rigorous nature of the standards surrounding cathodic protection, there are no graduate or postgraduate courses in cathodic protection engineering.

Cathodic protection specialists may start with a science or engineering degree, or via apprenticeships and trade skills, then augment these with specific training, experience and expertise.

The Institute of Corrosion offers both courses and certification in cathodic protection.

·         Courses in cathodic protection

ICorr cathodic protection courses provide the training required for levels 1 to 3 for cathodic protection data collectors, technicians and senior technicians in the sectors of buried, marine, and steel-in-concrete cathodic protection.

While providing the knowledge and skills training detailed in standard BS EN ISO 15257, existing experience and task competency are required depending on the course level.

These courses are suitable for those seeking certification of competence in cathodic protection in accordance with ISO 15257, and also for managers and others who wish to have an introduction to cathodic protection so that they understand what their staff or contractors need to be able to do and the limits of what they should do, within the scope of the standards.

·         Certification in cathodic protection

Independently of the cathodic protection courses, we also operate an independent assessment of competence. The ICorr Professional Assessment Committee (PAC) assesses whether the applicant has the requisite levels of experience, training, knowledge, and task skills as defined in BS EN ISO 15257.

This certification is recognised and valid internationally. In the UK, almost all steel-in-concrete cathodic protection projects, including those for Highways England (previously the Highways Agency), require cathodic protection personnel to be certified in accordance with ISO 15257. In addition, National Grid and the distribution companies, and many marine, port, harbour and offshore operators, also require certification of cathodic protection personnel.

Sustainability in cathodic protection provision

Cathodic protection companies will experience increasing benefits from having their employees certified in line with BS EN ISO 15257. They will be better trained, more competent, and better aware of their responsibilities. Clients are increasingly purchasing services from companies whose staff are certified in cathodic protection. For independent contractors, certification will enhance your reputation, help you to work more effectively, and give greater access to employment opportunities.

To learn more about our range of cathodic protection training courses and the experience and qualifications needed for certification, please visit our pages detailing the Cathodic Protection, Training, Assessment and Certification Scheme.

In our next article, we take a closer look at how cathodic protection works.