Hydrostatic test in pipeline gas

[Carlos Cunha]

Hello friends,

I would like to count on your support on two issues:

1- If a natural gas pipeline was built and tested (hydrostatic test) to operate at 35 bar, but it has always operated at 17 bar since 1990. my question is: I can consider this test still valid to operate at 35 bar and raise the pressure in levels, without the need to do another test, or I must do another test due to the long time that the test was performed.

2- In another existing natural gas pipeline (in a large dam), I also have to raise the pressure from 35 bar to 55 bar, I will test again, but this pipeline has metal losses due to corrosion along the pipeline, detected through the pig pass. My question is: Do we have to consider the thickness for the new hydrostatic test with negative tube manufacturing tolerances? Because there may be variations in thickness according to the manufacturing standard and there are possibilities for these losses of metal to be in a place with less thickness, increasing the risk of damage to the gas pipeline.

Thank you very much.

 

[1503-44]

Where is this pipeline. Your country's regulations may dictate what you can or cannot do.

1) Theoretically you could operate at design pressure. As I am often told, 1990 is now a long time ago. Lots of time for corrosion to take hold there. Practically speaking, I would think you would want to do an intelligent pig run first. What you can actually do may be limited by your jurisdiction and if the pipeline meets current regulations and is in compliance with all current regulatory documentation practices. It may also depend on pipe and fitting materials used. If the pipe is an old ERW, a new hydro might be the only prudent way. At the very least, please raise the pressure slowly. Very slowly.

2) You should evaluate the remaing strength of each and every anomaly found during your pig run. I assume it was an intelligent pig inspection, probably by use of ASME B31G or other method accepted by regulatory authorities of your country.

https://www.asme.org/getmedia/7336b61b-5762-47ca-bdcb-8a4e0de6f162/33501.pdf

 

[LittleInch]

In both of these instances you need to follow or develop a Management of change (MOC) procedure which commonly assess options, determines risks and then get everyone to sign off.

Many of the design codes have sections on this giving you some guidance including ASME B 31.8, section 857. Other codes have similar sections. Read them all as they offer different levels of guidance. Also any large company procedures for doing this if you don't have them yourself (Ask your friends).

IN terms of your specific issues,

1) As my friend Mr44 says, In theory yes, but if you go through a proper MOC procedure and do some sort of HAZID or other type of review procedure, I think you'll find that this is too high a risk option and would leave you open to massive damages if indeed the pipeline subsequently failed in service at your higher pressure. Five years after the original pressure test - may be ok. Thirty years later - Not OK (IMHO). I would expect a "Reasonable and Prudent Operator" to undertake at least some level of inspection to determine the condition of the pipeline. At a minimum this would be a CIPS survey and/or a DCVG survey to discover, investigate and repair coating defects. A few trial holes to determine the remaining effectiveness of the coating. Best by far would be an intelligent pig survey.

2) This is more tricky as you have knowledge of defects. If all you have is percent of metal loss then you need to start at the lowest possible thickness of original pipe and work from there. However if you don't repair and arrest the corrosion defects, then how are you going to allow for any corrosion growth? Again a robust MOC procedure will flush out these issues and lay them someone else plate to sign off on.



Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[0707]

Caro Cunha

You need to make a FFS (FITNESS FOR SERVICE) in your pipe line with a previous inspection with ultrasonic checKs to calculate if the pipe line can withstand the new operating conditions.

Cumprimentos

luis

 

[LittleInch]

Regardless of what the regulations say the key issue here is what defence do you have if by raising the operating pressure the pipe fails and then injures or kills someone or leads to massive loss of business and large claims of compensation. And so you can sleep easily.

So you need to do everything reasonable to do to convince yourself that the pipe is fit for its new duty short of total replacement.

what those reasonable things are will vary pipeline by pipeline depending on amount of data you have on the original construction (material certs, pressure tests, welding records etc),
Operating data such as number of pressure cycles, operating pressures and temperatures, any failures, or damage or movement.
Inspection data ( CP records, intelligent pig runs, any repairs or reinforcements ( e.g. fibre glass sleeves / clock springs etc)

Think of yourself being cross examined in court due to an incident and having to defend yourself and your actions. If you've done everything that could reasonably be done and the pipeline still failed then you shouldn't be convicted. If you didn't.....

Uprating or increasing operating pressure as you describe has high gains ( lots more gas through the same pipeline) but also high risks. The job of the engineer is to get those two in more or less balance.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

 

[1503-44]

Agree with that. It can be a subjective question. You need to take measures appropriate to the level of risk. A pipeline crossing uninhabited desert, no national parks, or endangered species around, might need minimal precautions. In extremes, you may be able to even re-establish pressure ratings with a "natural gas test". Offshore, beach crossings, wildlife zones, routing near inhabited areas, towns, cities etc needs a whole other class of both protective and proactive measures, a full hydro being only one of them.

 

[Carlos Cunha]

Dears
I greatly appreciate the help of all of you.

All of yours information contributes a lot to guide us in our work. We are doing a detailed study retrieving document history, tests, maintenance and others. We are doing MOC for both cases.

Sharing with you:
In case 1, (gas pipeline in the big lake), the pig was passed and several losses of metal were found, the largest being equal to 26% of the wall thickness. We evaluate the remaining life according to asme B31.G.
The percentage of SMYS during the tests points to almost 100% of SMYS, which worries us because any intervention in a submerged pipeline is costly and complicated, in addition to the risk to the environment and the company's image. We are evaluating all possible scenarios and conditions.

In case 2, even if the pipeline has been tested for the desired pressure, but this was a long time ago, we will pass an instrumented pig to evaluate the pipeline and then, if ok, do a new hydrostatic test. There are no reports of corrosion in all DCVG analyzes.

Thank you immensely for your support.

Carlos