Material Spec for High Partial Pres. H2S Gas Pipeline 6

[mcmidkiff]

What material specification should be used for gas piplines with high partial pressure H2S (P(H2S) = 4 psig)? I am under the impression that MR0175 does not address HIC, SWC, and others and that I should spec conformance with ISO 15156-2. The pipe vendors respond that MR0175 is equivalent to ISO 15156-2. I'm confused. Should I require Full Body Normalized? Do I need to specify a max on manganese and sulfur content? Also, should I spec Gr B or is X-42 okay? I'm concerned that the actual yield of X-42 may be as much as X-60. Is there a problem with full body normalized ERW vs. seamless?

 

[mcmidkiff]

I failed to state that the gas stream is dehydrated with about 3 mol% CO2 and 4000 ppm H2S at ~80 deg F. Eventually the pressure may drop from 1000 psig to 350 psig without dehydration.

 

[SJones]

Try and get hold of ISO 3183-3 for linepipe and look at the H2S containing service requirements in that standard. If those requirements are met then ISO 15156-2, NACE MR0175 will be met and surpassed.

Be careful with HFW pipe in H2S service - it can be done but select the pipe mills after thorough investigation and demand the weld SSC test that is optional in ISO 3183-3. Better still, get an experienced E&P Materials & Corrosion Engineer on board to help you as you will certainly need to assess the corrosion implications of running the line without dehydration.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[SJones]

I forgot to mention that you may wish to also look at ISO 15590 Parts 1, 2, and 3 for induction bends, fittings, and flanges respectively.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[PVRV]

1. NACE-MR0175 has been superseded by MR130.
Refer to this thread: thread338-82286

2. NACE-MR0175 does not address HIC, NACE-TM0284 proposes
testing methods for HIC without any guidance on
acceptance criterion.

3. Refer to this thread: thread286-83592 for proposed
specifications.

4. Seamless pipelines although restricted in diameter,
are idle for sour service.

5. I would be reluctant to use high strenght materials in
sour service; but then again depends on design pressure
requirements.

6. Alot of operators consider SAW (Spiral) and ERW
pipelines unsatisfactory for sour service. However,
recent development in HF-ERW has proven to be adequate.


Please post further clarifications after you have reviewed the above.


Cheers

 

[PAN]

PVRV,

This should be MR0103 instead of MR0130.

 

[mcmidkiff]

I've encountered a wide range of comfort level for 1000 psig, 4 psi H2S partial pressure pipe; from seamless to X-42/52 PSL1. The one person I've spoken with that experienced an SCC failure indicated that the failure occurred on a pre-1972 vintage LFW ERW line and that the SCC was confined to the weld seam. Is there evidence against using X-42 PLS2 full body normalized pipe?

 

[PVRV]

a. Thank you PAN, for the correction.

b. An increase in material strenght (yield/tensile) is
achieved in carbon steel through an increase in Carbon
or Manganese content. Both of which are restricted in
sour service. Elements that cause segragation such as
Sulphur and Phosphourus are minimized and considered
inpurities. (non-homogenious material properties) Plus,
suplhur promotes cracking.

c. Problem with high strenght carbon steel is the
susceptability to SSC.

d. Normalizing decrease secondary stresses in the
material as a result of fabrication this is quite
significant (upto 2/3 of the yield) even with perfect
normalizing (about 10% secondary stresses is retained)

e. Problem with H2S is the hydrogen which gets generated
as a result of a corrosion reaction in turn difusses
through the material wall and causes embrittelement.

f. With time, the material can no longer absorb the energy
and starts to crack. (losses toughness)

g. Such a fault condition leads to failure once, the
secondary stresses (increasing due to hydrogen
embrittlement) plus the primary stresses (operating
pressure) exceed the material minimum yield strenght.

Basically, omitting heat treatment of carbon steel materials in sour service substantially reduces service life; and vice is true.

PSL2 places maximum limits on the material elements; this places emphysis on the material quality.

 

[SJones]

Are you required by law or contract to use API 5L? Much like my view of NACE MRO175: to me, API 5L is history. No doubt a very useful specification in its day but the world has caught up with API, and ISO 3183-3 incorporates a lot of the extras that most purchasers usually impose on top of API 5L.

I'm working on a project with many BARS partial pressure H2S and have no problem with X65 HFW pipe provided it comes from certain pipe mills who have their act together. I had no hesitation in allowing DN400 X-65 HFW pipe for H2S containing service to go in 300 m water depth offshore Norway. Audit the pipe mill, qualify the pipe manufacturing (ensuring that strip edges are prepared by milling - do not allow rotary shearing) and in that qualification include SSC testing of the weld seam. Yes, there were horror stories with the old ERW pipe but shake off the past and move on. Incidentally, the installation contractor will also prefer HFW pipe over seamless because of better dimensional control. As to full body normalising: by all means specify it but a seam normalising treatment in a good mill is just as effective and will make the pipe a little cheaper.

MR0103 is aimed at refinery equipment whose conditions will, in general be very different from an upstream pipeline.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[PVRV]

mcmidkiff: take a look at NACE-MR0175/ISO 15156; I stand corrected about MR0103 scope.

Sjones: I wonder how many manufacturers are able to provide HFI > 400 Hz, the time impact associated with weld DT, flattening & microstructure examination, re-coiling tests,etc and how many manufacturers are willing to provide weld yield strenght values.

Installation contractors prefer plate tolerances as a pose seamless pipe tolerance; regardless of the welding process; however how feasible is it to weld X65 Carbon Steel manually

As for refineries, it is feasible to utilize alloyed materials in view of the relatively short distances involved or when the stream is dehydrated; such options are not readily avaliable for E&P operators.

On a different note, what type of flowline material does pdo utilize; ERW or GRE ? and what type of marine pipelines?

Cheers

 

[SJones]

PV,

The ISO 3183-3 requirement for HFW pipe is a minimum 150 kHz welding current frequency. Of the 2 or 3 pipe mills that I would be happy taking sour service HFW from (based on detailed appraisals), none of them use less than 250 kHz if I recall correctly. The time impact for the testing is not an issue (except for SSC testing but that would be an issue for all at 30 days duration) as the testing is offline whilst production continues.

Another driver to use HFW pipe over seamless is cost. At least it used to be 4 years ago when I was last seriously involved with pipeline costs before steel costs skyrocketed. HFW, being a more efficient production method, is generally cheaper than seamless.

It is very feasible to weld X65 manually. It is down to a routine basis here in the Middle East.

PDO's common flowline materials are seamless carbon steel and GRP. There has been a small dalliance with 13Cr and duplex stainless steel. PDO does not have any offshore operations.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[PVRV]

Dear Mr. Jones,

Several GCC operators require that only HFIW be utlized moreoever, > 400 Hz is mandated.

There is no doubt that ERW is cheaper and still inferior; by virtue of your current operation utlizing seamless pipes for flowlines.

As for welding X65; I beg to differ. It is difficult to weld steel with CE above 0.42 moreoever, the welding consumables are in the order of 80XX or 100XX. Slag inclusions was a prominent and substantial problem even in welding X60 joints.

As for GRP it is much cheaper that GRE; however GRP is inferior since permeability is a problem due to the absence of an internal liner.

ERW is banned in sour service and offshore application in our operation. Moreoever, spirally welded pipes are banned in our refineries. Both are utlized as protective sleeves or in utlities service.

Considering the recent developments in ERW; I would entertain its use in flowlines only and not gas or main transit lines else export lines. (onshore or otherwise)

I realise that either your streams are in the order of % of H2S or the system pressure is very high. Wonder, what the water cut is? since dry H2S service is one matter where as wet H2S is something totally different.


Cheers

 

[SJones]

PV,

Your company seems to be very set in its ways and that, I would say, is their loss. As to whether it is HFW or HFIW - to me, and to ISO, it is HFW - high frequency welded. Whether the welding is achived by induction or direct contact makes no difference in my view. I take it that you mean greater than 400 KILO Hertz frequency. Another urban myth that the GCC operators are serving to perpetuate because they lack access to contemporary experience and research results. Our operation uses seamless pipe for flowlines because we typically don't go above DN150 that is generally below the manufacturing range of acceptable HFW pipe mills. As to its inferiority, I fail to see the logic in that argument when we have many hundreds of kilometres of HFW pipeline installed and operating satisfactorily.

I agree that it may be difficult to weld pipe with a CEV higher than 0.42 but as we buy X65 with a maximum CEV of 0.39 the problem is diminished somewhat. Perhaps your company should review its purchasing specifications.

GRP = Glass Reinforced Plastic of which GRE, Glass Reinforced Epoxy, is a subset. The GRP that is in use here is all epoxy based.

The current project is high pressure and high H2S. The principal worry in wet H2S would be metal loss corrosion as the pipe specification will have addressed other degradation modes. Even if it is "dry" service, one must always cater for upset wet conditions and, fortunately, the only difference in pipe requirements will be the amount of corrosion allowance.

Regarding spiral welded pipe, I wonder how many thousands of kilometres of the stuff are in use in European gas transmission service.

It is unfortunate that your company appears to suffer some deep rooted prejudices regarding linepipe applications and struggles with welding. Good luck with your attempts to change things.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[PVRV]

Your apparent lack of appreciation towards pertinent welding processes involved in ERW fabrication is regrettable. I fail to see why you advocate the utilization of ERW pipelines and yet the Company you work for utilizes seamless pipelines and GRP; in addition to zero offshore operations; dispute your own cost and construction reservations. Quite a problem when your own technical judgement is not entertained by your current employer.

Moreover, the dismissal of API 5L is reckless to say the least; apparently there is no appreciation of the API monogram in manufacturer qualification. As for welding consumables and welding progression apparently there is a lack of practical experience in your case.

Furthermore, it is disappointing to see you argue against the norm; by virtue of the inconsistency in the discussion. It is suggested that upstream operators should not be considered with NACE-MR0103 and yet you emphasis wet H2S service.

In North America, SAW (Spirally Welded Pipes) are used for utility services. Then again, ignorance can be a bliss.

 

[PVRV]

Sjones,

If you are eager to learn more, there is a NACE paper (TR) regarding banning the use of ERW pipelines in sour service.

 

[SJones]

PV,

Many thanks for the offer. I'm always eager to learn. Grateful if you would quote the specific NACE reference to which you refer. In the meantime, if your company is a member of TWI, see if you can access TWI report 12953/9/02 The Use Of ERW/HFI Pipe For Sour Service.

I'll ignore the other disparagements.

Cheers.



Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[rorschach]

Mr. Jones, I'm concerend by your recommendation that full normalizing is really not required and that normalizing the HAZ is all that is needed. Have you never seen ringworm corrosion? normalizing just that HAZ effectively just moves the HAZ. you still get a stress gradient that will be a corrosion catalyst. Your lack of concern for this scares me.

 

[SJones]

Where does the "stress gradient" come from. Surely, ringworm corrosion is down to microstructural differences caused by improper heat treatment. Good pipe seam heat treatment leaves the weld zone and the pipe body material with a reasonably identical microstructure. If the pipe mill is in control of the process, it is perfectly satisfactory to have seam normalising only. HIC and SSC testing of the weld zone will identify any problems for H2S containing service. So, tell us, have you seen ringworm corrosion in HFW pipe or are you extrapolating from downhole tubulars? On the same basis, would you also advocate full body normalising of SAW pipe because of the HAZ left in the seam?

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[rorschach]

I'm extrapolating from downhole tubulars of course. But yes, I think that any welded part that is subject to H2S should be fully normalized to prevent stress gradients. HAZ's by thier very nature are a site of induced stress. Since H2S attacks through SSC which is a form of hydrogen embrittlement, stressed areas are more susceptible to it. I have seen a number of welds that failed in the HAZ through similar mechanisms. That is the whole point of normalizing to begin with.

For those who may ne know what ringworm corrosion is:

Downhole tubulars are upset on the ends to give more meat for the threaded area. Some manufacturers, to save money and time, will induction normalize just the upset area. others will normalize the entire tube. When you normalize just the ends, you have a HAZ just beyond the induction coil end. This has historically been characterized by a near perfect ring of corrosion right at the HAZ.

I cannot see how it would be possible to normalize just a weld seam without creating a new HAZ on either side of the heated area.

 

[SJones]

What type of welds have you "seen fail in the HAZ"? What about if residual stresses in HFW pipe are actually compressive (see Pargeter, R.J., Proc Conf Pipeline Reliability, Calgary, 2-5 June 1992) how will that impact SSC performance? Is it reasonable to extrapolate performance of downhole tubular materials to that of modern carbon steel strip used for HFW pipe? Is the metallurgy and response to the heat treatment processes the same? Don't forget that HFW pipe seam heat treatment may involve a water quench and that multiple treatments can be given in the production line.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/