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ASME B31 for two phase pipeline
- Thread starter DoraeS
- Start date
Your choice. In the houston area some ethane lines are B31.8 and some are B31.4 both operating at 1400 psig and 60F. I have even taken a line that was built and operated under 31.8 and converted it on paper to 31.4. We asked the DOT and they said just make the change and let them know so they could rearrange our inspections.
An interesting and frustrating question. I would look extremely closely at the scopes of both 31.4 and 31.8. I am going to stick my neck out to get somebody to respond. You might have difficulty with both as I have done. (Not in the USA). Some believe B31.8 is clearly not applicable. 31.4 is more vague depending on whether you want to support or oppose the argument. I believe it is down to interpretation and definitions of particular wording by whoever you are trying to persuade. For B31.8 you might want to look at 802.12 especially paragraph f).
(I don't have 31.4 in front of me so I can't quote the paragraph). One thing is for sure - don't do a thing until everybody including the independent inspector's dog has signed up in blood. Also consider the intent behind the codes and how this ties into your service. Why are allowable stresses higher for pipeline codes? Fluids with low corrosion rates, low risk of damage due to location and burial etc.
(I don't have 31.4 in front of me so I can't quote the paragraph). One thing is for sure - don't do a thing until everybody including the independent inspector's dog has signed up in blood. Also consider the intent behind the codes and how this ties into your service. Why are allowable stresses higher for pipeline codes? Fluids with low corrosion rates, low risk of damage due to location and burial etc.
There are a lot of ways to skin this chicken:
- Count the wells that were permitted as oil and the wells permitted as gas and go with the one with the most wells.
- Calculate mass flow rate of liquids and gases from the two streams and go with the biggest mass flow rate.
- Calculate the sales value of the two streams and go with the one that contributes the most value.
B31.8 is more forgiving of liquid in gas lines than B31.4 is about gas in liquid lines so you might weight the decision in favor of gas.
None of these is "right" and none of them is "wrong". My approach would be to pick a justification, write a memo to file explaining the reasoning, and get on with it.
David
- Count the wells that were permitted as oil and the wells permitted as gas and go with the one with the most wells.
- Calculate mass flow rate of liquids and gases from the two streams and go with the biggest mass flow rate.
- Calculate the sales value of the two streams and go with the one that contributes the most value.
B31.8 is more forgiving of liquid in gas lines than B31.4 is about gas in liquid lines so you might weight the decision in favor of gas.
None of these is "right" and none of them is "wrong". My approach would be to pick a justification, write a memo to file explaining the reasoning, and get on with it.
David
FOR INCOMING OIL & GAS LINES ONSHORE
The answer is.... NEITHER.
B31.4 and B31.8 DO NOT even apply to gathering systems.
Notice the title of B31.8
Now check the scope.
How please explain how does B31.8 include "Gathering Systems" when it specifically denotes a difference between "Transmission and Distribution systems" and "Gathering Systems" in regards to the title of the code?
You will find similar wording in B31.4
If you have further doubts, you can check the legal requirements in the US, CFR Title 49, Parts 192 for gas and 195 oil pipelines here,
Look at the Scope of each Part.
192 (Gas)
194 (Oil)
Gathering systems NOT INCLUDED.
Its not only your choice, you don't have to use any code except what is required by your company policy.
FOR OFFSHORE GATHERING SYSTEMS
DOT CFR TITLE 149 DO NOT APPLY
SEE MMS REGULATIONS
The answer is.... NEITHER.
B31.4 and B31.8 DO NOT even apply to gathering systems.
Notice the title of B31.8
Now check the scope.
How please explain how does B31.8 include "Gathering Systems" when it specifically denotes a difference between "Transmission and Distribution systems" and "Gathering Systems" in regards to the title of the code?
You will find similar wording in B31.4
If you have further doubts, you can check the legal requirements in the US, CFR Title 49, Parts 192 for gas and 195 oil pipelines here,
Look at the Scope of each Part.
192 (Gas)
194 (Oil)
Gathering systems NOT INCLUDED.
Its not only your choice, you don't have to use any code except what is required by your company policy.
FOR OFFSHORE GATHERING SYSTEMS
DOT CFR TITLE 149 DO NOT APPLY
SEE MMS REGULATIONS
BigInch,
You are more or less correct, but if housing moves in to encroach on a gathering system then 49 CFR 192 becomes applicable and if you did not build the system to a code then it is really expensive to retrofit to the code. This is happening a lot these days as groups of mobile homes set up on top of old gathering systems. I've done several over the last few years and by the time you do the calcualtions, take the system down for a new static test, and x-ray accessible welds DOT has forced you into actions that result in the pipe looking like it was built to a code.
There is no downside to building gathering piping to code, you have to have some basis for design decisions and B31.8 is better than most.
David
You are more or less correct, but if housing moves in to encroach on a gathering system then 49 CFR 192 becomes applicable and if you did not build the system to a code then it is really expensive to retrofit to the code. This is happening a lot these days as groups of mobile homes set up on top of old gathering systems. I've done several over the last few years and by the time you do the calcualtions, take the system down for a new static test, and x-ray accessible welds DOT has forced you into actions that result in the pipe looking like it was built to a code.
There is no downside to building gathering piping to code, you have to have some basis for design decisions and B31.8 is better than most.
David
In my case above, we applied all the way the the secretary of the department of transportation to clarify and received no responce. Just pick a standard and live with it. If you pick B31.3 (I've seen that too), then live with it. If the line becomes jurisdictional to DOT as zdas04 says, you'll have to live with what you did, including the recreation of all missing documents and inspection.
Encroachment happens to transmission lines too, which changes the design factor. We just learn to live with it and deal with it in advance, if you can, or on a as needed basis, if you can't. Its all the same.
I know pleanty of privately owned gathering systems that just install pipe....whatever pipe... with a preference for dented pipe....NO DESIGN AND NO CODES... no hydrotest... no inspection... no corrosion control program, no nothing. Its really scarey how thin a wall thickness you can get with 100% smys and a little corrosion. Talk to them about code and you'll get run off with a shotgun.
I know pleanty of privately owned gathering systems that just install pipe....whatever pipe... with a preference for dented pipe....NO DESIGN AND NO CODES... no hydrotest... no inspection... no corrosion control program, no nothing. Its really scarey how thin a wall thickness you can get with 100% smys and a little corrosion. Talk to them about code and you'll get run off with a shotgun.
BTW, personally I'm in favor of no difference for gathering systems. They all should be regulated under the CFRs. I've seen what happens when they're not.
OK BigInch, lets go ahead and shutin about 23% of all domestic production because a 10 mcfd line at 10 psig is not up to some code and the consumer will suffer, not the companies. The risk for gathering lines is so small, its not worth the added expense, so the wells will be shut in.
Well first, I don't believe that 23% of domestic production comes from 10 mcfd-10 psig gathering lines. You wouldn't be able to walk between all the large diameter lines anywhere in Tx. The specific cases I was thinking about were 1440 psig lines w/ 10-100 MMCFD, some with 4.5% H2S, and which I know can afford to be built to code. Even if they were built to code now, all benefit would be lost when they are not operated to standards. Nobody even knew where half of those lines were or where they went. A B31 design doesn't help much when there is no corrosion control program, no inspection, no maintenance and all relief valves are locked off. If you're happy with 2 or 3 explosions each week... or BP Alaska getting shut down and you and the rest of the consumers paying for the oil price rise due to the shortfall ... why not?
If encroachment happens on a transmission line that has been built to B31.8 and inspected per "good engineering practices" then you simply have to redo the calcs with a different design factor. This generally results in lowering the line's MAWP which often isn't a show stopper.
On the other hand an old GCNM line that was built with uncoated, dented, thin wall pipe was a major problem to bring up to DOT specifications. Nearly impossible in fact.
David
David Simpson, PE
MuleShoe Engineering
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.
The harder I work, the luckier I seem
On the other hand an old GCNM line that was built with uncoated, dented, thin wall pipe was a major problem to bring up to DOT specifications. Nearly impossible in fact.
David
David Simpson, PE
MuleShoe Engineering
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.
The harder I work, the luckier I seem
The 23% represents all the feeder lines into the big one you know about. Think about all the production lines too that were built with 2 3/8" upset tubing or discarded 7 inch casing. Like you, I wonder how some companies can operate 1000 psig lines as non jurisdictional, but they did it by shutting down field dehydrators and called it raw gas. OH GREAT, now you have wet gas at 1000 psig. My point is at some combination of flow, pressure, location, and what not, the risk to reward isn't enough to replace or build new lines to meet DOT codes.
BTW, would you want a DOT regulated pipeline operating at 2200 psi in your backyard, I've done that and I was still scared to death as that line went 200 yards from a high school....
BTW, would you want a DOT regulated pipeline operating at 2200 psi in your backyard, I've done that and I was still scared to death as that line went 200 yards from a high school....
Nope. Worked for the producer. The specific lines I refer to were directly off the 982 wells and a whole bunch in the gathering system from the Laredo Airport south down to the La Perla Ranch, behind the Casa Blanca Restrauant, eventually reaching about 50 miles south to Zapata. When we got into the H2S, I didn't want to hang around for obvious reasons, so I got back on 59.. that time pointing NE.
BigInch has got my vote. The next time I come under pressure (ouch!) to accept 31.4 and 31.8 for wet sour service flowlines I know where to come.
(Its strange that all the hot shot experts are able to redefine the scope of the Code and sit on the fence - leaving you on your own when you have to make a stand and say nuts. Funny old world).
(Its strange that all the hot shot experts are able to redefine the scope of the Code and sit on the fence - leaving you on your own when you have to make a stand and say nuts. Funny old world).
The scope of the codes are the easiest provisions to "change" to suit one's own purpose. Since nobody ever reads those sections, the wool fits comfortably over the eyes.
But is there really a problem with expanding the scope? I can see where contracting the scope would be a bad thing, but if a section of pipe simply is excluded from all of the codes what is wrong with picking one that is close and building to it? It does add some construction cost but it also gives you a design basis that keeps the design engineer from having to make up his own construction standards.
David
David
Nothing at all.. as long as you know you're doing it, I guess, which implies you know where that code ends and where you might have to pick up another one. I'd just say, if you use a code, know its limitations... all of them.
Hence, each company needs to decide and can make the dicission based on risk versus cost. Here's my favorite scenerio, Liquid pipelines must have block valves on each side of a river (ok body of water, swamp..) to reduce the risk of a spill. What about ethane or propane, can they spill in a river?
Provided they are competent to do so. IMO they're a lot that arn't. Even if they do, they still must operate appropriately. Also a lot that arn't.
The smart aleck answer to your question decastro is, "YES! If you design/build and permit to/under CFR 49 Part 194 / B31.4". They sure can. The solution (?)... you'd better have those valves, or apply for a variance and waiver beforehand.
So... that's what regulations and codes don't do for you.
The smart aleck answer to your question decastro is, "YES! If you design/build and permit to/under CFR 49 Part 194 / B31.4". They sure can. The solution (?)... you'd better have those valves, or apply for a variance and waiver beforehand.
So... that's what regulations and codes don't do for you.
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