By Michael Osborne
Anti-corrosion coating failures are a significant factor in reduced operational life of pipelines.
The failure of a pipelines coating system accelerates corrosion and can result in leaks requiring repair, cleanup and in some cases replacement of the pipeline, which can be very expensive.
The cost, environmental impact and negative publicity associated with failures are something every major oil and gas company seeks to avoid.
In the past ten-20 years, failure analyses of pipelines have been performed by a variety of companies, agencies and special interest groups, in an effort to reduce or eliminate failure incidents.
These analyses are public information and contain a variety of good data.
Failure analysis data can be feasibly applied only to coating systems that have been in wide use over a period of time.
The data derived from the studies of pipelines in operation for 20 years or more are conclusive while evidence about pipelines operating for a shorter duration are not as clear.
The majority of traditional coatings have been widely used for more than 20 years, so there is extensive information readily available regarding their performance and failure frequencies, allowing for clear conclusions to be made about their long-term compatibility as pipeline anti-corrosion systems.
Most failure analysis studies include different comparisons for groupings that include pipe type, pipe wall thickness, operating temperatures, and media being distributed by the pipeline, etc.
The resulting data from each of these comparison studies varies slightly depending on the combination of variables included in each comparison, yet the principal conclusions derived from the studies are constant.
Principal Causes of Traditional Coating Failures
The principal causes of pipeline failures, with the definition of failure being a leak, include external corrosion, internal corrosion, third party damages, operating errors, design flaws, equipment malfunction and maintenance and weld failure.
The leading factor for pipeline failures in all studies has been by far attributed to external corrosion.
As stated previously the different studies include a wide range of variables, but in all cases external corrosion was the top cause of failure.
In fact, many failures attributed to third party damages were in fact damage to coating systems by third parties either during construction or otherwise that resulted in failure of the coating system followed by failure of the pipeline.
External corrosion is the leading cause of failure but by itself is misleading as there are several different coating types (even bare pipe), operating temperatures and other variables included in the studies.
Methods of Avoiding Coating Failure Instances
The most common cause of pipeline coating failure is due to impact damages during transport or construction that are not properly repaired.
The second leading causes of coating failure are found at girth welds (field joints) that are attributed to failure of field coating of the girth weld areas.
The third leading cause of coating failures is related to cathodic protection systems failure.
Some studies indicate slightly varying percentages for specific failure types but all of them are consistent in that these three items are the top three and comprise the majority of all failures.
Avoidance of these three common failure causes is a primary goal for all end-users, and on the surface would seem to be fairly simple to resolve.
All major oil and gas companies are aware of these issues and have developed and implemented rigid quality assurance and construction implementation plans that include steps to reduce them, yet they remain the primary causes of coating system failures worldwide.
The failure instance rates of each of these items are much higher in third world countries (where lack of equipment and qualified personnel increases the failure instances exponentially).
But it remains a key problem even in the most professional of installation environments.
The most obvious solution to reduce the failure instances caused by impact damages during transport is to eliminate as many transport and handling steps as possible.
Many pipe manufacturers now include coating facilities within the plant to eliminate transportation to and from a pipe coating facility at another location.
Traditional pipe coating facilities are not mobile, have high power consumption levels and require a high level of environmental control to work effectively.
This condition is typical of FBE and Tri-laminate products.
To reduce coating failure instances found at girth weld field joints the end-user should use a better system in the process.
FBE coatings have improved methods of field jointing that bring the field jointing quality close to factory levels, yet these systems are not used the majority of the time due to the high costs required for their use and the difficulty of bringing the equipment required to the joints in the field.
The most common field jointing method used for field joining FBE and Tri-laminates remains shrink-wrapping of the joints.
When installed properly, shrink-wrapped joints perform fairly well, but again the process of properly installing them requires diligent installers and is time consuming.
Time constraints on projects, weather and other factors result in a high percentage of the shrink-wrapped joints being completed to less than ideal conditions.
In the best of conditions, shrink-wrapped joints present two circumferential seams at every girth weld.
In a pipeline of 100 kilometers using 12-metre double random pipe, that amounts to 17,500 circumferential seams, including a factor of 105% for bends, fittings and other field modifications, or one seam every 5.7 lineal metres of installed pipe.
No matter how this is justified, the result is a lot of seams and as everyone knows seams are prone to failure.
Michael Osborne is the president-CEO of Nukote Coating Systems International, specialising in advanced polymers and coatings in the energy sector.
He can be contacted at: