Despite technological advances, the ideal onshore pipeline coating system does not yet exist
More advanced pipeline coatings offer benefits but are not problem-free
Operators need to choose the right coating for specific conditions
Independent third-party expertise can improve coating selection
Selecting an anti-corrosion coating system for an onshore pipeline is a complex challenge whose goal should be to closely match a solution to an operator’s specific needs. The financial and reputational cost of failure can be high, a fact reflected in the global market value for on- and offshore pipeline coatings across all industries, which Research and Markets has recently estimated to be worth nearly USD12 billion by 2020.
The positive benefits of using the best corrosion protection coating for the job are potentially: lower pipeline inspection, repair and maintenance costs; improved safety and environmental sustainability; and, pipeline lifetime optimization.
New pipeline coatings expand choice
Onshore pipeline coatings have evolved substantially in response to demand from pipeline operators transporting oil and gas from and across more challenging and remoter environments and terrains. Coal tar enamel (CTE) and asphalt (bitumen) were the first-generation material of choice in the 1940s, and the widening of coatings options since then includes second- and third-generation systems introduced since the mid-1980s (figure 1).
Operators are now confronted by a wider range of choices. They need to look carefully beyond developers’ and manufacturers’ technical information and marketing claims to be sure of selecting the best coating for their specific requirements”
Dr Christopher O’Connor principal consultant - pipelines technical advisory, UK and West Africa, DNV GL - Oil & Gas
“The new coatings systems involve novel application techniques to extend the design lives and performance of components they are intended to protect,” observed Dr Christopher O’Connor, principal consultant - pipelines technical advisory, UK and West Africa, DNV GL - Oil & Gas.
“Operators are now confronted by a wider range of choices. They need to look carefully beyond developers’ and manufacturers’ technical information and marketing claims to be sure of selecting the best coating for their specific requirements.”
There is no ‘perfect’ coating system at present
In an ideal coating system, key criteria for selection would be met perfectly. These include adhesion of the system to the pipe; applicability; chemical and thermal stability; mechanical properties; and, economics (figure 2).
Second- and third-generation coatings have removed or reduced some problems associated with the first generation, including:
- significantly reducing stress corrosion cracking (SCC) as one main threat to pipeline integrity
- alleviating microbially-influenced corrosion (MIC)
- eliminating thermo-mechanical coating degradation
- reducing the level of coating damage sustained and hence in the current needed for cathodic protection
- created the ability to fully integrate the pipeline coating system.
“Despite advances, there is no such thing as an ideal coating for all purposes,” O’Connor added. “A wide variety of materials is used for coating and wrapping pipework and fittings. All have different functionality, though the key function is to prevent corrosion.”
Problems with onshore pipeline coatings
Reasons for failure of coatings since the 1940s include: application problems; biological attack and MIC; induced alternating current (AC) interference and stray direct current (DC ) interference; mechanical resistance; thermo-mechanical properties; SCC; and, stress cracking of polyethylene (PE) coatings.
Most problems have been with first-generation and early second-generation coatings. New generations of coatings are generally better than older ones. ”However, some pipeline operators still use first-generation coatings such as tapes and heat shrink sleeves (HSSs) to protect field joint areas, and the new coating materials can also bring their own problems,” O’Connor added.
Reported issues using second- and third-generation pipeline coatings include:
- Increased susceptibility to AC and DC corrosion in areas influenced by induced AC and stray DC interference
- The latest three-layer polyethylene (PE) field joint coatings being developed tend to be labour- and time-intensive, making them expensive to apply for onshore applications
- Using first-generation coatings – tapes and HSSs – on field joints protected with second- and third-generation mainline coatings can cause susceptibility to MIC, SCC, and thermo-mechanical degradation at the joints.
Selecting the right pipeline coating
Fusion bonded epoxy (FBE) and polyolefin-based coatings – which include three-layer polypropylene and single-, two-, and three-layer PE – together account for 80% of the global pipeline coating market, according to developers and manufacturers Bredero Shaw.
The use of various systems varies geographically. FBE is a popular choice in North America and for onshore gas transmission pipelines in the UK, for example. ”Our technical and advisory work on legacy gas tranmission pipelines in the UK confirms that these coating systems have worked without any problems,” O’Connor said.
”Three-layer systems are used for this purpose pretty much everywhere else. They have proved themselves, though there is room for improvement,” he continued. ”For example, there are questions about whether adhesion of some three-layer systems to pipelines is as good as it could possibly be. Clearly, standards in the sector need to be of the highest quality to ensure high-quality products that are fit-for-purpose.”
Coating tests should simulate real-life conditions
International and national standards exist for the two critical steps in coating a pipeline effectively: technical qualification of the coating, and preparation of the pipe or field joint to ensure the coating will adhere. In addition, DNV GL’s new Recommended Practice DNVGL-RP-F106 Factory applied external pipeline coatings for corrosion control provides a guideline to the specification and execution of coating application work.
Standards evolve alongside the development of coatings and experience in the field, but they can only go so far, O’Connor commented: ”Going the extra distance means developing and using defined tests that ensure that a coating will both meet international standards and also do the job expected of it in specific environmental conditions. As for preparing pipes, it is probably the weak link in the coatings application process. Significant development is underway, which is exciting for the market. Qualification of the new products is just as important.”
The value of independent expert advice
The key message, said O’Connor, is that operators cannot rely purely on procurement departments reading manufacturer’s specifications and claims for coatings: ”It is good practice to undertake a vigorous, comprehensive review of design criteria including the application, where the system will be used, and the operating environment, such as external and internal pressures, and temperatures. Some operators have internal experts on coatings, but consulting independent third-party experts can help to reach the right decision objectively.”
DNV GL, for example, provides qualification, certification and verification for manufacturers in accordance with accepted procedures. It advises operators on materials selection for coatings; independently reviews and audits coating systems so operators can check fitness-for-purpose; and inspects pipelines during construction.
’Introduction to Pipeline Coating Systems’, C O’Connor, I Thompson, DNV GL, 2017 whitepaper.
Contact Dr C O’Connor (details above) for more details.
DNV GL prides itself on providing accurate information but makes no claims or guarantees about the accuracy, completeness or adequacy of contents in this publication, and disclaims liability for any errors or omissions. The authors’ views here do not necessarily reflect DNV GL’s views.