Corrosion Growth Rate of a Gas Pipe line

[09091960]

Recently we had our ILI run for our 22” gas pipe line. One of the major out comes of this 2008 ILI run going to be the prediction of corrosion growth rate and our repair plan for the next 5 years. As the vender had done 2003 run as well as 2008 ILI runs they are going to overlay the data for the defects so that , can calculate the growth rate for N number of defects and finally come into a conclusion that corrosion growth rate for each section before having our repair plan.
Appreciate if you could provide me with some information on calculating the corrosion growth rate as I have come across many different approaches and formulas for calculating the corrosion growth rate for buried gas pipe lines

 

[SJones]

If you have come across many different ways to address the problem, which one do you prefer? You will get the same number of conflicting answers on here. If the corrosion is believed to be a result of wet CO2 corrosion, then it would be a very good idea to get yourself a corrosion prediction model that your company is happy to work with across its operations such that you can start playing with future operating scenarios. You can then start looking for papers on remnant life prediction and IMR philosophies for pipelines. Or, you could hire in a qualified and experienced consultant.

Steve Jones
Materials & Corrosion Engineer

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

 

[brimmer]

09091960,

You seem to have many questions on pipeline integrity, I guess that is what the forum is for. What I would suggest is you use more than 1 method, complete different scenarios with different methods/rates. The underlying premise to which you suggest you are using 2 ILI runs and calculating a site (or specific corrosion anomaly) rate in my opinion is the way to go. I am not sure about the ILI tool(s), same tool or generation of tool? If they are different generations this can lead to a less accurate correlation. Also, don't be fooled by the ILI vendors statements around accuracy of sizing, most of the runs will have outlyers which are beyond the error bars of the tool, the error bars in reality may be larger than what the tool is specifying. Use your field correlation data you collected, and apply this, not just the ILI data as is. In some cases, this field data may help to narrow the error window and help give a tighter rate. Some companies have data from many different vendor tool field correlations, and have developed their own error bars associated with each tool and apply these. One of the issues around an ILI vendor completing everything is it will be all automated, and perhaps won't have much manual interpretation around anomaly matching. Some of the new methods include an error factor in field measurement as well, they take into account for different methods of measurement (i.e. pit gauge, ultrasonic etc.). I might suggest you use a consultant with experience in this type of analysis rather than 1 ILI vendor. In your analysis on the financial side you want to include some cost calculating on what if you inspect your worst features or some features that can delay the run of an ILI tool a year, or two years etc., based on cost per dig and ILI run. If you are DOT liquid line forced to run every 5 years anyway, this part of the analysis may not be worth (or a detailed analysis may not be worth it) it when the POE will not exceed 5 years in any case. You also must decide what you want to live with, POE on full bore rupture or any leak depending on your company (assuming you go the POE method on top of a determinstic method). Other factors might include class 2 and 3 areas where you might not want to exceed a certain burst pressure etc.
I could go into more details, but your question was very broad and it is dificult to describe methodolgies in full... Perhaps I did not answer what you wanted.

 

[abduh137]

IMHO, comparing 2 latest ILI data should be able to be utilized to calculate more accurate of actual corrosion rate. But you should taken care different corrosion mechanism especially localized corrosion since this kind of corrosion has different thermokinetic than those general uniform corrosion which is largely modelled as in Norsok or ECE Model. You should consider other model for specific variables effect concerning with localized, multiphase gas, etc.

But as the hi-res ILI result provide identification of SCC or pitting you can secure your conclusion by the operation constrain of water cuts, partial gas, temperature, solid that will not introduce new corrosion mechanisme to your pipeline.

 

[09091960]

Hi All,

Fortunately our pipe line hasn’t reported any internal corrosion defects as yet. Further we have been carrying out our ILI runs every 5 years. As our pipe line is almost 30 years old , management is happy to continue the ILI runs every 5 years. Like they had done it in the past I prefer to calculate the corrosion growth rate based from past ILI runs. As Brimmer noticed my background of experience was from marine top side piping and not much exposure to buried pipe line industry. Quite rightly Brimmer pointed out that having a forum is all about exchanging our experiences and sharing the views. Appreciate all (S Jones,Brimmer & Abduh) for contributing for this topic.

 

[SJones]

You must have a very tame management if they are happy to see an ILI run every 5 years on a routine basis! The problem with looking at the ILI data in isolation is the one of having to answer the question: did any corrosion occur uniformly over the 5 years since the last run; or, did it all occur in the last 5 months? ILI data on its own is not going to answer your question. You will need a raft of other information such as operating parameter histories, other corrosion monitoring data etc etc to form an opinion of what is happening to the pipeline. Take a look at NACE SP0206 to get some idea of what is involved. If you can amalgamate sufficient data resources you may be able to present a case for extending the next pig run interval beyond 5 years and save your tame management some heavy expense which you, of course, will expect to see a share of on your salary slip!

Steve Jones
Materials & Corrosion Engineer

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

 

[brimmer]

I think you will be able to demonstrate with a proper POE you can push the ILI runs beyond 5 years, 5 years is conservative, this is assuming you are completing the excavations after each ILI run on the larger anomalies and are eliminating many anomalies each time. This is also assuming you are diligent in the other integrity activities, such as a cathodic protection system etc. and the line is in reasonable shape. You might do a POE and find that the line requires re-inspection in under 5 years... I would suggest some sort of analysis is required regardless of whether you want to extend the re-inspection beyond 5 years or not, to make sure no leaks occure before 5 years, given that you have not had a leak (assuming) in these 5 year intervals before, you should be okay. Many of our POE's come out in the 7-10 year re-inspection interval. If your line is critcal from a business stand point and may have higher consequences if it does fail, you might not want to exceed 7 years.