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How to remove debris from internall

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Green white

Green white

Mechanical
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Jul 7, 2022
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How to remove debris from internally coated pipeline with (TK 236) prior to commissioning (pigging or flushing)?
the pipes is 24in and the length is 55 KM.
the line pipe joints welded together using insert sleeve
 
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Foam pigs.

Or soft cup pigs.

Or lots of water at 5 m/ sec...

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is pipeline with internal INSERT SLEEVE piggable ?
 
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You said internal coating TK 236.

What exactly is an insert sleeve?

Drawing, sketch or link would help clarify.

How much does it reduce the ID?
Did it have a sharp edge?
Why has it been used?

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@LI - Google Thru Kote sleeve. It’s an internally coated sleeve with a heat resistant tape such that it can be welded on without coating damage giving a coated field joint. A foam pig should pass it.

Steve Jones
Corrosion Management Consultant


All answers are personal opinions only and are in no way connected with any employer.
 
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This is why I love this site, you find new things all the time.

Never seen these before, but seem a bit OTT to me. Any time I've looked at options to transport corrosive fluid, internal coating has been regarded as too high risk as application, inspection and potential for even a small piece to disbond or become damaged is seen as very difficult or likely to happen in the typical 25 Yr life of a pipeline.

I still can't find out how thick these are though and hence what reduction in I D is. Also are the end rounded?

Thinking a bit more, what sort and how much "debris" are we talking about? You might need a bypass pig to jet 10% of the flow through the pig. Or maybe a soft cup pig, either a single body moulded pig or perhaps a coated foam pig to last 50+ km.

I would strongly recommend that you contact some suppliers and service companies from this association. They are world wide.
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Also: If you get a response it's polite to respond to it.
 
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Screenshot_2023-10-15_132435_lmdjrr.png


Steve Jones
Corrosion Management Consultant


All answers are personal opinions only and are in no way connected with any employer.
 
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I'm with LI on the "internal coating for corrosion control is a bad idea" front. I've been fighting it for 30 years. Given that the line is internally coated, how much 'debris' is actually expected? There's no rust or scale for starters, although there could be a lot of flaking coating[pipe]

Steve Jones
Corrosion Management Consultant


All answers are personal opinions only and are in no way connected with any employer.
 
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What fluid is running in this pipeline?

--Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."
 
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Steve,

Great someone else agrees with me!

Any idea of dimensions? I found a lot of nice pictures but no dimensions drawing or table.

So maybe 8mm?

That would be >95% ID.

But it's the constant clipping over 50+km I would be worried about. Pigs don't like that.

Did no one think of this before you built the pipeline??



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The inside diameter of the pipeline is 584.2
The inside diameter of the insert sleeve is 556.2 (95.2% of the pipeline inside diameter)

Is the pipeline pigable?
 
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You need to choose the right pig and let the supplier know these dimensions, but 95% is feasible.

Still a higher risk than a smooth ID so choose carefully.

And whatever you do make sure the pig(s) have trackers so you can find it if it gets stuck or breaks up.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
 
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A 4-inch sleeve uses Sched 40, so 6.02 mm thickness. I don't have any data for other dimensions.

Steve Jones
Corrosion Management Consultant


All answers are personal opinions only and are in no way connected with any employer.
 
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The data above from the OP says the 24" is about 14mm thick(!).

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Also: If you get a response it's polite to respond to it.
 
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the total length of the pipeline is 55 Km
the ground profile is almost flat
can we make the hydrostatic test without segmentation, or we need to divide the pipeline into smaller segments and conduct the hydrotest for each segment separately?
and in such case, how many segments we need ?
 
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Depends on:

Test pressure and what that is in terms of % SMYS of your pipe
What the min and max elevation is along your pipe. YOui would be surprised what "almost flat" means to different people.
Calculate the difference in head between test pressure at the highest point (usually the test requirement) and pressure at the lowest point.

Then see if the pressure at the lowest point results in an SMYS of 90% or less.

If it is then you're ok, if not then you need to segment up the pipeline.

You commonly find the min to max elevations is in the order of 125 to 150m, but each pipeline is different.

Post the full elevation vs distance, pipe size, wall thickness , SMYS and test pressure and then we can have a better look.

This is pretty basic stuff though - Is there no one in your company who can help you?

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
 
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The test pressure at the highest point is equivalent to 90% of SMYS
The test pressure at the lowest point is equivalent to 96% of SMYS
The hydrotest envelope of 90–96% of SMYS, so I assume it is acceptable.
The pipeline is constructed near the coast flat area, almost flat.
Do we need to subdivided the pipeline into smaller sections ?

it is a study case
 
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On those figures no you don't need to segregate the sections for hydro test

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