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Up Topic Welding Industry / General Welding Discussion / 7018 on crude oil pipeline with H2S present.
- - By NMWELDING (**) Date 09-28-2007 18:19
Way back when I started my portable welding business an old timer told me that you must use low hydrogen rods on pipelines where hydrogen sulfide was present. He said not to use 6010 or a cellouse coated electrode. I have always done that since then. This involved facility hookups and gathering lines where the crude oil and natural gas was sour. I cannot for sure remember the reason, but I thought he said it was a cracking issue. Any comments on this will be appreciated. Thanks.
Parent - - By jon20013 (*****) Date 09-28-2007 18:47
I've always heard (and practiced) the same and, in fact, there is an API standard (believe it's specific to hot-tapping) that says the same thing.  Also, minimal preheats, normally around 100F (speaking from memory).
Parent - - By js55 (*****) Date 09-28-2007 19:34
Cracking associated with H2S is actually a form of HIC (hydrogen induced cracking). Not a good idea to add to the H2.
Parent - - By jon20013 (*****) Date 09-28-2007 20:31
Especially when you're in breathing distance from the joint!!!! :=0
Parent - By js55 (*****) Date 09-28-2007 21:19
Thats a fact. Suplhuric acid reaks havoc on a pair of lungs.
Parent - - By aametalmaster (*) Date 09-28-2007 21:34
H2S will kill you quick if high enough levels. I assume you mean after the line was properly prepared to remove the H2S from the pipe then weld. But the incoming crude oil would have H2S in it. I work in a refinery and almost all the piping is 7018 except for the SS pipe which is Tig....Bob
Parent - By dbigkahunna (****) Date 09-28-2007 23:26
Crude oil gathering lines are commonly welded with 6010 rods. There are thousands of miles of pipelines which are in use welded that way. When it comes to sour gas, that is another thing. A SMAW process for plant service would be either a tig or LH root followed by LH fill and cap. But cross country and trunkline gathering systems are welded with 6010 rods. Plants and refinerys are another thing. THe reason is simple cost and fittness for service. On cross country pipelines the enemy is pitting type corrosion. The consequences fo a failure are low. In a plant or populated area, the consequences could be dramaticaly different, so you want to use a procedure that will lower the consequence of failure. But in the environment in th eoil patch right now, most company people do not know come here from sicum about welding process, procedures or worse, cost factors.  So they let welders use what ever they have rolling around in the truck.
Parent - - By downhandonly (***) Date 09-29-2007 00:11
6010 bead and hyp or 70+ the rest of the way is what is done around here and I've been in some the sourest patches around(that's mainline only!!!) the above ground lines are 6010 bead 7018 the rest. 100% x-ray on everydamnthing no execeptions!! preheat is the key (especially where I've been it's winter access only because of the muskeg. -40 really sucks and so do cracks.)have fun!
Parent - - By Shane Feder (****) Date 09-29-2007 12:10
Hello guys,
A little question that has baffled me for years, hopefully someone can clear it up for me.
A pipeline comes into a compressor station, processing plant, refinery etc and it is a buried pipeline and usually it is designed,built and inspected to API 1104 and is welded with 6010/7010.
The first joint above the ground after the riser is usually designed, built and inspected to ASME B31.3 and welded with ER70S/E7018 or E7016/E7018.
Even if there is an isolating valve between the API 1104 section (after the weldneck flange)and the B31.3 section it is still basically the same pipe (I realise one might be API 5L and one may be A106 Gr B but it is the welding acceptance criteria I am concerned about) , and if the valve is opened then both sections are exposed to the same pressure of fluid.
I have always thought that the reason for the different acceptance criterias was that one was buried so could better absorb an explosion and the other was above ground so was more exposed.
Are my assumptions correct or is there another reason why they differ ?
Thanks and regards,
Shane
Parent - - By dfwpipeliner (**) Date 09-29-2007 16:31
I have ben working on compression stations and mainline pipe recently and use 5p+ 6010 for root, and weld out with 70+ 8010.    This is on both plant and pipeline in North Texas. The only time LH 7018 rod is used is on hot taps.  Is this not the norm. 
Parent - - By Cole Welding (**) Date 10-01-2007 04:17
how much work is there???
Parent - - By js55 (*****) Date 10-01-2007 14:00
The pipeliners are right. Cellulosics are used on services with H2S every day. Gotta be a threshold thing, as well as the the risk assessment thing touched upon.
Parent - - By pipeliner01 (**) Date 10-01-2007 14:48
about that H2S thing, I've  done a number of corrosion digs with a reputable contractor out here (Alberta). The particular oil company we were working for (Petro-Canada) had their own set of procedures for tieieng into an existing line that was in sour service: preheat to 400, held for 15 min. allowed to cool to touch then heated again to 400, allowed to cool, then both pipes are put into the clamps and pre-heated for welding-6010 bead and 7010 hot/fill/cap.  This worked really well, didn't even get any of that hydrogen stink. I guess their idea here is to basically cook out the hydrogen that absorbs into the steel.
Parent - - By downhandonly (***) Date 10-02-2007 03:12
there are reputable contractors out here?lol
Parent - - By pipeliner01 (**) Date 10-02-2007 03:34
I think all of sedgewick works for them, pretty clicky but they could keep a fella busy, they had 7 crews going through the spring w/ that big slow down.  Stupid me turned down another big job with them when I was in BC
Parent - By Cole Welding (**) Date 10-02-2007 11:45
do you have a number???  what is the pay out there??
Up Topic Welding Industry / General Welding Discussion / 7018 on crude oil pipeline with H2S present.

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