Stating pipeline life in years can be a pointless. The pipe would reach the end of it's life when one of the original design parameters is exceeded. That would usually be corrosion or the number of full stress cycles. Hard to accurately relate corrosion to service years. Best to just measure it as it happens. Piping design by default is 7800 thermal stress cycles which happens to be one startup per day for 21 years.

You also may see design life related to EQ design. This about owner's and public risk and does need mean you need to shut the line after 25 years.

thanks KevinNZ

Actually i want to know injection of corrosion inhibitor how long )approximately can increase lifetime the pipeline? what is the relation between injection and life time of pipeline?

You can also add extra pipe wall thickness as corrosion allowance, but depending what you have in the pipeline, it may not be as effective as corrosion inhibitors. You can internally coat a pipeline to resist your corrosive chemicals. In some cases you might need to do 2 or more methods.
Lifetime depends on the expected corrosion rate given your method of resisting it.
Sour crude can be extremely aggressive on bare steel, in some cases eating just the bottom of the pipe, or welds, ignoring extra wall thickness of the rest of the pipe.

If you have hot salty sour crude and bare steel walls, your pipe may not last 1yr, or it may last 2 or 3, or 5. So it depends on how aggressive the crude is. With the right inhibitors and dosage, it may last 5yr, 10 or 25.

What is the stream analysis, temperature and your treatment program detail?

"One of the my colleague says that corrosion inhibitor injection has not any credit to lifetime of pipeline and without the injection the pipeline lifetime should be 25 years. Of course he said that this subject is applicable for any pipeline. Is He right? the pipeline is 10 km sour crude oil with 50 barg pressure."

Your colleague is an idiot.[IMHO]

If the design life is 25 years, then in the design when the corrosion rate is calculated, they will take into account the beneficial impact of the CI - usually 90 or 95% "effective" and calculate the required corrosion allowance from there.

No CI, no protection - lots of corrosion - leak within 3-5 years.

The calculations they do are not to be taken as gospel - corrosion can occur in isolated locations and result in leaks and it's not a uniform thing.

A few years ago some idiot on a working oil field worked out that they could stop injection of CI for 5 years, allow the pipeline to corrode down to nearly min wall thickness, then start again. "saved" a small fortune in CI, the person moved on and in less than 5 years, the gathering system started springing holes everywhere. They ran an intelligent pig and there was serious metal loss all over the place - result, reduced operating pressure, reduced throughput and a very expensive repair and replacement program many times the "saving" from not injecting CI.

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

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Your colleague is an idiot.[IMHO]

I am not fluent in English but I think the word of "idiot" is a little far from polite in technical discussion.

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No CI, no protection - lots of corrosion - leak within 3-5 years.

I am working on offshore platform and in one of the field there is a 28 inch pipeline from offshore platform to transfer the almost 100,000 BPD crud oil to the Island. This pipeline is in service from 1975 up to now.(45 rears). In a 20 recent years (from 2001) due to failure of C.I system there isn't any injection to the pipeline and no problem has been reported respect to this pipeline.. The length of pipeline is 140 km.

Ok, idiot was a bit far - maybe misinformed.

The point is to know why CI is being used. Sweet dehydrated Crude oil or even with water up to 20% that flows reasonably fast will have very little internal corrosion. Practice and knowledge of corrosion in the 1970's was a lot lower than now and the use / injection of CI was seen a "standard practice". Nowadays you only add it if you need to to inhibit corrosion from something like CO2 or H2S.

Lots of corrosion is in isolated locations with pitting and can take many years for leaks to occur. Unless you're checking internal corrosion using intelligent pigs then you are just flying blind.

The design of the CI is usually to use up the Corrosion Allowance of 3-4mm max in the design life, so you still have design wall thickness left. In reality you use up the CA plus maybe 60-70% of your design wall thickness before you get a pinhole leak.

But if you're into 1-2mm/yr corrosion uninhibited then you have not a long time, especially if i't fairly thin pipe. Your 100000 bbl/day pipe is probably ~24" and 15-20mm thick? A 12" 8mm thick pipeline will corrode faster.

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

That's a big change from the 10km sour crude pipeline you mentioned at the beginning.

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That's a big change from the 10km sour crude pipeline you mentioned at the beginning.

Thanks for your Careful consideration, but the case at the beginning and last mentioned are two different offshore platforms. As I said at the first case corrosion inhibitor is continuously injected to the pipeline but for the last case C.I has been stopped since 2001.

Yes, but if the contents are different then so will the corrosion issues.

Just because one pipeline survives doesn't mean the other one will...

Your colleague is still wrong.

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

Quote:

he point is to know why CI is being used. Sweet dehydrated Crude oil or even with water up to 20% that flows reasonably fast will have very little internal corrosion. Practice and knowledge of corrosion in the 1970's was a lot lower than now and the use / injection of CI was seen a "standard practice". Nowadays you only add it if you need to to inhibit corrosion from something like CO2 or H2S.

thanks for your good explanation. I know H2S and CO2 content are high but i don't know the exact amount of these in crude oil. I only know the amount of H2S and CO2 in the outlet associated gas (outlet gas of separators) is 20,000 ppm (each) and there isn't any gas sweetening system. Also the water cut is 25 percent.

That's fairly corrosive. Temperature and pressure have an impact as well.

My guess is that's about 1-2 mm/Yr without CI.

With CI is about 0.1mm/Yr.

So yes, you can avoid CI for quite a long time, but your pipeline is unlikely to get to 25 years life.

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

So when they stopped the CI did they change how the line is monitored and inspected?
This is all a task of risk management.
After all most equipment does not have a finite life.
It has a point in its life where the risk increases.
Then you begin inspecting more carefully, and more often.
And likely also do more frequent maintenance.
And at some point the risk and/or cost of repair exceed what is acceptable and you replace it.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, consulting work welcomed

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One of the my colleague says that corrosion inhibitor injection has not any credit to lifetime of pipeline and without....

Quote:

In a 20 recent years (from 2001) due to failure of C.I system there isn't any injection to the pipeline and no problem....

It seems that the operations of these piping systems are deviated from the engineering design conditions. IMO, no matter who said okay in the past, you may understand it to be a potential safety issue, and if any alternative to correct it.

Many, many and many pipelines do not use any corrosion inhibitors. It all depends on what is flowing in the pipeline and the flow conditions. If there is no active corrosion taking place, CI is not required.

142846,
To know if your friend is right or wrong, you have to go back and look into the design basis by the EPC to find out the criteria for the wall thickness calculation. If they have considered the impact of CI for determining the CA.
We also know that the design life is not a cast and stone when it comes to actual life. It's a parameter for designing the pipeline. You must be having an integrity program to assess the pipeline. Usually, customers like you will run a in-service FFS and decide to run/repair or replace the line.

GDD
Canada

Perhaps we are not quite reading what your colleague actually may have meant. It could be a confusion between the terms 'design life', and 'remnant life'. In designing the pipeline, the objective has been set to achieve a defined lifetime. This defined lifetime is independent of any construction and operational activities deployed. These activities are developed and executed with the aim of ensuring that, at any given time, from pipe mill to planned cessation of operations, the assessed remnant life of the pipeline meets, or exceeds the lifetime required by the owner. Corrosion inhibition activity may contribute to achieving the necessary remnant life, but it doesn't change the required life.

The relationship between inhibitor injection, and the remnant life of the pipeline, is the reliability of the injection process. Also, why focus on inhibition? What about coatings, for example ? Remnant life isn't only driven by the inside environment.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

Exactly, coating, among other methods, were mentioned above.
"You can internally coat a pipeline to resist your corrosive chemicals. In some cases you might need to do 2 or more methods."

I meant EXTERNAL coating - pipelines can corrode from the outside too.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.