Material Selection for the flow line

[Normankhan]

For the well stream composition.We are considering the line pipe material-API 5L Gr X65, as per NACE MR 0175.

One has suggested to select Carbon steel with Corr.Allowance of 1.6mm is this selection Ok with this corr.allow??

Considering Line pipe API 5LGrX65 is it also suitable material and what corr.allowance would be sufficicent if we consider 3 yrs service life of flowline??

Alternatively we would like know what will be the selected material and CA in case the design life of flowline is 20 years.

Attached is the well stream composition data.

kindly reply at earliest with all details/answers and formulas used for corr.allowance and service life.

 

[zdas04]

With that much H2S I'd be nervous about X65 pipe, the internal stresses are high enough to to support SCC without much pressure. I generally have to have a really good reason to go much above Grade B/X42 dual stamped pipe. NACE document MR0175 has the necessary arithmetic to evaluate that risk.

David

 

[brimmer]

Carbon steel with your suggested parameters would be acceptable for the code where I am, and we build carbon steel flow lines for sour gas gathering all the time. Corrosion allowance depends on you, you won't get specific guidance in a code. Our code allows us to go to X70 for sour service. You can caluculate a corrosion rate with your gas paramters, some programs out there will do this, but I suspect rate would be high enough that if you try a 20 year life span, it would be prohibitively thick. Worst corrosion will be water hold up and where in your line. What we do is apply corrosion inhibition and maintnenance pigging to give the lines much more life with a minimal corrosion allowance, operate flow lines like this for 30 years in some cases with no issues.

 

[SJones]

http://www.eng-tips.com/search.cfm?q=corrosion allowance&action=search

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[zdas04]

Brimmer,
Good advice. I would argue that pigging without the chemicals would give exactly the same life expectancy, but chemical salesmen have to make a living too.

I see people going to higher grades to try to make the pipe walls thinner for the same MAWP. If the expected line pressure is much above 15 Bar(g) at X65 the SCC calcs get me too close to a failure point for my comfort with the data (i.e., the failure point lies within the dead band on the data).

The corrosion rate calcs all start with a liquid-full system. In a gas line I've found them to fail to be representative of observed data.

David

 

[brimmer]

With corrosion rates, it is possible to claculate one given his gas analysis, but the big issue I find with trying this is approach is what will be the pitting rate (which would cause the first leak). Very difficult to predict just from a gas analysis, and will depend on how you operate the line, areas of water hold up etc., which is why you would normally do some sort of flow modeling, get gas velocity to see if you have good sweep, etc when we are assessign a gas gathering system.

David is correct pigging is very important if you do nothing else, as you will remove (at least much) of the free water. I dont know his line conditins, I assume a very typical flow line. We have done some studies and are in the process of doing more studies with internal corrosion working groups where we test a control, then with pigging only, then with pigging & chemical, then chemical only, then various solids and combinations as well. We have found that chemicals do have a positive effect if used alone with no pigging, and if used in combination with pigging. It will vary depending on flow conditions though. You also have to have the right chemcial to start off with.

As far as grade of pipe, we certainly have been operating at least grade X52 for years without issues of SSC, hardness is important.

 

[zdas04]

The problem with chemicals in gas lines is transport to where the water accumulates. What I always find is that without pigging the chemicals will all accumulate in the first few sags and low points and get no further. With pigging, the distribution is better, but still not great.

Are you going to publish your findings? I've never seen any high-quality data that even indicated (let alone proved) that chemicals by themselves had any impact at all on corrosion rates in a gas line.

David

 

[brimmer]

Normankhan, I have attached a document which is available in the public domain. It is not exactly what you asked for by your approach, but a best management practice for operating sour gas lines related to internal corrosion, use it as you wish, but understand it if you do use any of it is my advice. I guess where I am going is your service life will depend on how you operate & maintain the pipeline as opposed to just selecting a corrosion allowance, & carbon steel can be used for a 20 year life; but in the end the decision is yours, perhaps your operations cannot maintain a robust maintenace program and you have to consider something else.

 

[SJones]

It's not really possible to calculate a general metal loss corrosion rate given that the corrosion mechanism is H2S dominated. CO2 yes - but there isn't really a model for that much H2S that has been used in anger. Freecorp from Ohio Uni could give a stab in the semi-darkness. You may be surprised at what rate you actually get with that much H2S owing to film formation if the temperature, pH and chloride content are amenable. The biggest risk is pitting and a corrosion allowance is no real defence against that. For the OP, he may wish to refer to the CAPP document

http://www.capp.ca/getdoc.aspx?DocId=155644&DT=PDF

The Canadians probably have the greatest experience with the highest H2S contents.

Would the OP like to give us a location of the intended three year flowline so that I can stay well away!!

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[SJones]

Snap


Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[brimmer]

hmmmm,

FYI - Normankhan we oeprate sour gas lines with as high as 35% H2S with carbon steel, but I am not necessarily giving advice to use it

 

[Normankhan]

Thanks for the answers.
could any one provide me free or trial software download link for electronic corrosion engr) ECE-V4 or 5???
Norman

 

[blacksmith37]

As an old guy I like simple things that have worked before; there are a brizzillion miles of gathering line made with cement lined Grade B ( 5L,
A-53, even furnace weld/bell weld ,whatever) verwhelming amount has been satisfactory.

 

[SJones]

Why Electronic Corrosion Engineer?

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04

 

[zdas04]

Blacksmith,
Me too. I have to have a REALLY good reason to go above Grade B/X42 dual stamped pipe and with piggable lines (that get pigged) the corrosion performance of my designs has been about perfect.

David

 

[blacksmith37]

I guess an Electronic Corrosion Engr must have a I pad/pod.
"Sour" service began in La Laq France, then to East TX, then the rest of TX, LA, etc. Today,even China has had some serious H2S pipline failures.

 

[SNORGY]

8% to 10% H2S is routinely handled up here with the metallurgy described by zdas04. At the Regulatory level, the corrosion failure potential is addressed through controlling stress levels (limited to certain percentage of yield strength) and mandatory sour service operating and maintenance programs that include mandatory in-line inspection.

Regards,

SNORGY.

 

[zdas04]

The key is managing stress and standing water. We tend to forget that there are two flavors of stress: we all think of stresses imposed by pressure, but we often forget the matrix stresses inherent in higher grades of steel and corrosion resistant steels. Using Grade B or low "x" numbers minimizes those stresses.

David

 

[SNORGY]

X65 (Grade 448) would also add a lot of extra welding requirements (according to Z662 at least; can't imagine it would be much different in other parts of the world). Up here, go one grade higher to Grade 483, and that is the Code limit on SMYS for any sour service pipeline. All of which appears to add further validity to zdas04's recommendations.

Regards,

SNORGY.

 

[SJones]

Well L480 is a bit different to keeping at L245! It's a little difficult to glean from statistics how much SSC there has been in pipelines as it seems to get lumped under internal corrosion. I'm quite happy to see L450 in H2S service and would only avoid SAWH of the normal pipe manufacturing routes. With chemistry and hardness control, it's been leak before break in my experience.

Steve Jones
Materials & Corrosion Engineer

http://www.linkedin.com/pub/8/83b/b04