Limit for CP "ON" potentials 2

[09091960]

Under CP,Our burried gas pipelines are protected through 850 off criteria. This is referred to variously as “850 off”, “polarized potential” or “instant off potential”.
This criterion is applicable to impressed current and galvanic systems where the
protective current can be interrupted. Further the "off" potetials have a limited value of -1100 m V maintained in our pipeline to avoid hydrogen evolution which can damage the coating. As our pipeline is old and have coating issues we find dificulty of protecting some sections of the pipe line under"850 off" criteria. Having said that we experiance that we can achive the protection levels by incrasing the "ON potentials" by driving to much higher limits than usual(-1800 m V). Our consultant opnion is that as well as for "off potentials" there should be limitation to "ON potentias" and they are also indicative of the voltage stress applied to the coating and has limited to the "on potentials" of our pipeline to -1400 m V. Whats your thought on this subject. Any papers or past experiance that help me to clarify this issue? Appreciate your feed back.

 

[LittleInch]

I am surprised no one has commented on this, but although not an expert I've seen enough CP systems to think that you consultant is correct.

ISO 15589 and NACE RP 0169 might give you more guidance, but for old pipelines it is very common for low protection sections or spots to be provided with additional sacrificial anodes or additional transformers and ground beds to "boost" the protection from remote impressed current systems without turning the system up so much that other sections are being "fried".

Hope someone with a bit more in depth knowledge than me answers your question.

My motto: Learn something new every day

Also: There's usually a good reason why everyone does it that way

 

[brimmer]

I think this question was asked before. Some comments. Since the polarized potential is indicative of the amount of current that is actually reaching the pipe, this is the more critical value in terms of on or off potentials. If you have a large IR drop (from high soil resistivity or other factors) you will have difficulty protecting to -850mV off limiting your on potentials to -1400mV on. As a rule of thumb we limit to -2500mV, but not for reasons of coating stress, more for safety. I would challenge your CP vendor to present evidence first that a non-polarized potential is affecting coating, and certainly a non-polarized potential of only -1400mV. I have attached a report which has a section on overprotection, you will see nothing in relation to on potentials and overprotection, nor will you see anything in other literature as it is the polarized potential which is indicative of what current level is reaching the pipe/coating. If the ground bed is close to the pipeline, you may have coating stress in these localized areas, these areas are the main concern for voltage stress on coatings. Current density as far as current voltage stress is the only true way to understand / put a value on this issue, not from on / off potentials, but this is harder to measure in the field and not every CP vendor will have this expertise. It also seems that the number -1400mV is the standard polarized potential applied for cathodic disbondment test, so I don’ t know if your vendor sees this value in the literature and is simply telling you to limit on potentials to that number, not understanding. The amount of cathodic disbondment will actually depend on other factors besides potentials / density, coating thickness, soil moisture, soil pH will effect amount of disbondment at the holiday greatly. There is a PRCI paper PR-75-9609 (Cathodic disbondment of pipelines coatings under realistic field conditions) that explains some of this, though again in the paper there are no guidelines for on potential, only effects of polarized potentials, current densities, and soil conditions on cathodic disbondment. There is also a NACE task group working on issue of overprotection, you could consider asking your question on the NACE forum where there are many CP specialists (although that doesn’t necessarily mean much) as opposed to this forum where there are not many integrity related people on it.
Some options if you want to limit on potentials to -1400mV:
Install additional rectifiers at lower potential areas, this could be costly and the hardest part is usually getting AC power hook up to those locations.
Complete CIS, find larger areas of poor coating, recoat these areas. Pipe won’t require as much current for protection and can keep rectifier outputs down. Usually costly, but could be worth it in the long run or if there is no other solution.
Move to a 100mV criteria, would need native potentials .
I would only recommend localized anode installation as an absolute last resort. If you go this route, I would bring the cables up in a bond box, so you can disconnect or interrupt the anodes, otherwise you will never know what the true polarized potential is for those areas.

 

[09091960]

Thanks LittleInch for your comments and encouraging others to join in this discussion.

 

[09091960]

Wow, excellent explanation from "brimmer". Lots of facts that I can take it back to our CP vendor and request for his justification for limiting the on potentials for -1400mV.
"brimmer" talks about limiting to -2500mV,mainly for safety reasons. What are the safety conserns under high on potentials for a pipeline? What is the condition of your coating and do you carryout DCVG surveys to your pipeline? Due to poor coating conditions, our pipeline is unable to manage under DCVG as the number of repairs are very high. Therefore we manage under a srtict ILI program. When did you change your on potential criteria to -2500mV? Have you increased it gradualy within many years to arrive at -2500mV ?

 

[brimmer]

We typically need higher rectifier output in sandy or rocky soil, where soil resisitivty is higher and there is a large IR drop. Coating conditions on pipelines vary, from good to poor. We typically do not do ECDA surveys unless we have gone the DA route for assessing that pipeline, we normally complete assessment with ILI. If we have an issue where we can't get adequate protection without installing more rectifiers and know there is a coating issue, we may complete CIS and recoat larger areas. When you have coating that is very old,of course you will have disbondment/holidays, you simply will not be able to repair them all, that is why you have and maintain a CP system, and use ILI. There should be a severity scale with your ECDA report and you would only target the more severe locations. Your main concern is the areas which are actively corroding, if the CP is working at a holiday and there is no corrosion, why excavate and repair it? For us, completing ILI and DCVG on all our pipelines simply isn't practical, the ILI data will tell you where you have corrosion and thus coating issues. I won't tell you that more data isn't better, and you shouldn't do both or try to repair all coating issues, but I question the practicality. DCVG can tell you where there is a holiday, but not corrosion which is what you are concerend with, whereas the ILI data which you have will. I won't comment on your CP vendor without more knowledge of your situation. The other thing is some coatings shield CP (such as tape), so you can have larger areas of disbondment without a coating hoilday, DCVG or CIS won't be able to detect this, so you have detected holidays from your DCVG survey, but not necessarily other pockets of disbondment where there is no holiday or a very small holiday, so what about these areas you can't even detect? The ILI data will tell you if there is corrosion there. You get my point? -2500mV used as a guideline to limit step potentials and creating sparks.

 

[09091960]

Thanks Brimmer for the explanation.

 

[09091960]

As we are in the subject of On potential, I thought that I should discuss the following to get others opinion.

In few of our compressor stations which separates the main pipeline from the station the insulation joints are buried. Therefore there is a section, which immediately goes under ground to the buried IJ is not protected (Approx 12 Meters). As per vendors recommendations we had followed a localized ground bed design to protect the 12 meter section of the pipeline. Due to various reasons we are unable to polarize the plant side and therefore cannot carry out the On/Off criteria as specified in the standard. Hence the vendors recommendation is to carryout spot On potentials for every meter for 12 Meter section as part of the full line survey for main pipeline. With comparison to CP standards I find it difficult to justify the On potential criteria which we have been using under the given circumstances. Appreciate your thoughts on this issue.

 

[LittleInch]

Do you mean that the 12m section is protected by a sacrificial anode system?

If this section is plant side of the IJ and no other isolation then the pipe will be earthed inside the plant no? It doesn't sound very surprising to me that you have no potential as all the current is just leaking away or have I misunderstood your situation? A small sketch might be useful here to define your issue.

My motto: Learn something new every day

Also: There's usually a good reason why everyone does it that way

 

[09091960]

Yes the 12Meter section is protected by sacrificial Anode system. Further as you understood the 12M section is on the plant side and unable to polarize it. Have you come across burried IJ as similar to our pipeline condition?

 

[LittleInch]

Yes,

I've seen this a number of times although it is not the best solution, partly because the buried section of pipe on the plant side is unable to be protected by CP. This is because there is no electrical isolation (this is what the IJ is doing) between any CP input ( n this case your sacrificial input) and the plant pipework which is either earthed properly or effectively earthed by all the support connections, instruments etc. Therefore any potential applied to the pipe promptly dissipates back to earth - hence no potential.

Any time I've seen it and it comes up in the HAZOP, the mitigation is to thoroughly inspect the buried section of coating and then apply extra coating or wrapping to provide further protection in lieu of the lack of CP.

Unless you can electrically isolate this section from the plant ( in which case why didn't they put the IJ there?) your sacrificial anode is doing nothing and is a waste of space.

Without seeing it or any drawings it's difficult to say why this solution was put forward.

My motto: Learn something new every day

Also: There's usually a good reason why everyone does it that way

 

[brimmer]

So I would assume the ILI tool did not get through these sections? If it did not you might be doing some digging, to demonstrate there is no corrosion there. Short of this if you have a flange on the upstream side of these joints, if feasible install an IK and your sacrificial anoded will work fine.

 

[09091960]

Gents (Brimmer/LttleInch) - Thanks for your feed back.

This section of the pipe was excavated and repainted 8 years ago. Under the most recent DCVG carried out in this year shows that overall coating condition of the pipeline is good. Having said that vendor couldn't carryout DCVG for this section as he was unable to put a signal due to isolation issues.