How determining the ‘Confidence Factor’ on component corrosion condition can positively influence integrity failure.
Last week I was discussing business with our company accountant, and he mentioned something he had seen in the Oil & Gas press that morning. Apparently the BP Claire platform had been shut down because of a component failure. I told him I had seen that article too, but he pressed; “so SCM are dedicated to managing and preventing component failures from corrosion – how come these things keep happening”? It was a good question, they do seem to keep happening with alarming regularity. Now, first off, I really don’t know the ins and outs of the BP situation, and one cant help but think that with a more targeted and focused inspection process, these potential failures will be spotted and eradicated long before they actually occur. Easier said than done however, and whatever the type of failure they suffered, it still raises the same questions for us when we consider our market sector; the external corrosion of physical assets. Why does it happen and how can we stop it?
In the oil and gas industry (and most pressure systems industries to be fair) billions of £’s and hours have been dedicated to seeking answers to these two questions and yet we have only one or two ‘partial’ solutions that operators and owners appear to consider valuable! Namely, tools such as Risk Based Assessment & Inspection, and general corrosion prevention maintenance works. With this ‘tiny’ range of tools at our disposal to help us predict and identify potential component failures from external corrosion, it’s not surprising that we still have so many unexpected incidents, or is it?
The bald truth is that, really, there is only one reason for an unexpected corrosion failure of a component – They didn’t know it was a problem!!!
How ridiculously simplistic is that? If they knew it was in bad shape, they would obviously fix it!
Three years ago we undertook an analysis for a client and discovered that more than 13% of all substrates in their plant complex (which included many individual facilities) was in an unknown condition and had not undergone inspection since the plant was commissioned. They didn’t know if it was good or bad, if it might fail, or last another 20 years. I would gamble that I could discover a similar situation on almost any on-or-offshore mature facility today!
Good engineering practices these days demand that Integrity and Corrosion Engineers make some ‘educated’ assumptions and yes, even guesses, based on certain ‘samples’ they gather from visual and other types of inspection. These samples are typically considered representative of other similar items:
If ‘this’ 1m long section of gas pipe is in condition ‘X’, then all the other ‘similar’ pieces of gas pipe will be a in a ‘similar’ condition. Hence this 1 m section represents the entire pipe. Assessments can be a little more intricate than that, but essentially that is how the process works.
Let’s follow this process for a moment and see if we can’t spot a flaw or two in it:
- A Risk Based Assessment is carried out on a ‘gas’ pipe that runs for 60metres around a process plant. The assessment considers:
- Metallurgy, process, temperatures and age of the pipe plus a range of other base-pipe-makeup factors.
- Any potential corrosion mechanisms that ‘might’ affect the life of the pipe, and any corrosion mitigation factors that are going to be applied to prevent degradation in future.
- Based on this assessment, and an experiential knowledge of the general corrosion degradation of plant in that geographical environment, a ‘factor’ based on the assessed consequence of failure and its probability is calculated. Let’s call it a criticality-factor for ease where, criticality-factor 1 is the most onerous and 5 the least.
- Corrosion protection might be applied (coatings for example) and maintained every 7 – 12 years or so.
- Integrity inspection will be scheduled on the pipe, based on the criticality-factor, for example, where the pipe was classified as criticality-factor 1, then a schedule of inspections would be considered similar to this example:
- Inspection of 5% of the pipe every 6-12 months, and record its condition.
- Monitor any observed degradation.
- Where wall thickness is lost, then re-calculate the life expectancy of the component pipe and re-schedule the next inspection for an appropriate time.
For new, or reasonably young, process facilities these tools and techniques can suffice, even offering a significant comfort factor that corrosion is well managed. However, when a plant could be considered ‘mature’, perhaps 10 years old or more, the astute readers among us will likely spot all of the possible negative issues this process might suffer?
At first glance it looks like the perfect solution; Assess a component, figure out what could go wrong and keep checking to make sure it doesn’t!
Well, perhaps not. If it was, then “hey, no failures”. Except we do get external corrosion failures all of the time, so what gives???
The process is incomplete. Even after all of the assessments, the multiple and hugely expensive inspection regimes implemented and the endless analysis engineers pore over, they STILL don’t know where to look!