Inspectioneering Journal

Don't Overlook the Value: Questions and Answers from the Inspectioneering Discussion Forum

By Greg Alvarado, Chief Editor at Inspectioneering. This article appears in the September/October 2007 issue of Inspectioneering Journal.
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Editor's note: This archived article has been published because it contains technical information that may still be relevant to you. However, the Inspectioneering Discussion Forum, referenced numerous times below, is no longer maintained.

The Inspectioneering Journal Discussion Forum is a great storehouse of knowledge and experience for people involved in fixed equipment reliability. It often represents industry best practices and references, helpful industry codes and sources. You can register and hopefully participate, although you may visit just to read the interchanges, by clicking on the “Discussion Forum” link on the Journal home page or click here to go directly to the forum portal.

At the portal you may view the archives, no interaction is possible here just tons of good reading.

To participate in the forum click on the “New Discussion Forum” link. A few samples of discussions follow, to motivate you to participate:

TMLs, CMLs, Piping Reliability Enhancements


What is the best way to select the TML’s “Thickness Measurements Locations”?


To answer one of your questions, regarding TMLs (now referred to as CMLs in the API inspection codes):

The best way is to have an industry and unit specific experienced corrosion engineer perform a corrosion systemization and circuitization of your piping and vessels identifying corrosion systems and circuits at the PFD and P&ID levels, respectively. Color coding these documents works well. Then with a firm understanding of damage mechanisms locate CMLs (condition monitoring locations, because thinning isn’t the only mechanism necessarily found in piping and equipment) on their respective circuits. More is not necessarily better if you are looking in the wrong locations and with the wrong NDE techniques and the old methods or rules of thumb using inspectors and inspection companies to pick the locations are no longer sufficient.

I would also recommend you draw a one to one relationship between your corrosion circuits, the RBI (risk based inspection circuits) and you inspection database management system (IDMS) circuits. This ensures that there is optimal correlation between them and that you take full advantage of the piping RBI efforts, i.e. inspection strategies, including timing of inspections, is easily used by your scheduling program, typically your IDMS, SAP, or CMMS program.

If you are using an RBI program, these circuits, just as the circuits in your IDMS, should have a well-defined parent/child relationship documented between them and your inspection isometric drawings. You should begin getting better, i.e. with less scatter, correlation of corrosion rates within the same circuits with this approach. This means your CMLs or TMLs for will all be placed on these corrosion circuits. The weakness of past practices, for the most part, were that TMLs were placed on circuits defined as from equipment item to equipment item. This is not a true corrosion circuit approach. That is one of the reasons, probably the principal one, why it has been so difficult to have confidence in managing piping inspection programs using circuit rates.

Further enhancements would include defining material operating envelopes for your units and using these to proactively manage the assets and adjust strategies proactively. There are controllable and non- controllable parameters to monitor. This can be as detailed as you like. When this and the practices mentioned above are leveraged and done by the same team, there are some tremendous learning synergies that occur, too.

Another enhancement, when you have documented a statistically significant number of thickness readings to satisfy the confidence level you desire, and you get good statistical curve fits, is using this information to further optimize the number of CMLs, for thinning mechanisms that is, and use trending to alert you to mechamisms you may not have anticipated.

One of the first references I would pick up is the API RP 571 document covering damage mechanisms and NDE in refinery units. It does not replace a good, experienced corrosion engineer, though.

Welding Dissimilar Metals


When welding 5Cr 1⁄2 Mo to 2 1⁄4 Cr 1Mo,we have two Welding Manuals with conflicting suggestions. One states that the weld consumable for the lower alloy being joined should be used (E9018), but the PWHT procedure will be for the higher alloy and the other Manual states that the weld consumable shall match the composition of the higher alloy of the two materials being joined - E502 or a mixture of ER90S B3 for the root and E502 fill. Any comments would be appreciated.

Answer 1:

Without knowing your exact application and intended service conditions here are my comments, if you have a specific application please feel free to email me with more details.

Normally when joining dissimilar Cr-Mo steels, a filler metal with a composition similar to the lower alloy steel or to an intermediate composition is commonly used in butt joints. In this application there would be no reason for the weld metal to be stronger or more resistant to creep or corrosion than the lower alloy base material.
Now if you are welding attachments to a higher alloy main structure I would use a filler metal that will provide mechanical and chemical properties equivalent to the higher alloy main structure.

Just keep in mind that each welded joint must possess the required properties for the intended service following PWHT.

Answer 2:

When joining by welding P5 to P22 you can use P5 or P22 as filler welding. The best solution would be to choose a filler metal with an intermediate composition between P5 and P22, maybe a mixture of ER90S B3 for the root and E502 fill is the approach to this. In any case the welding procedure must be qualified. It seems to me that in this case PWHT is always required.

Fabricating U-Tubes


During re-tubing of “U” tube bundles we have found that the available material was not the correct one, instead we have straight tubes where we fabricated U bends as per original dimensions then we welded it to the straight section with 100% radiography. Is this accepted by the code? Is it right practice? If not, which code does not allow that and why?

Answer 1:

For exchangers, I suppose that according to TEMA code, “U” tubes shall be cold bended followed by stress relieving the cold bend forming, so it will not be acceptable to have “U” bends welded to straight tubes. Your option should be understood as a resource one because on zones adjacent to the welds the corrosion process will be accelerated. As soon as possible you should change to “U” tubes as per TEMA code. My answer is only based in “good practices” for exchangers’ tubes replacement.

Answer 2:

Answer 1 comment of cold bent + SR is the naturally best practice. But in case of this sort of problem as faced by the questioner which others also may have experienced, some practical and technically acceptable alteration should also be thought of. It is quite logical that a welded coupon could have some potential weak site compared to a bent one. But if a procedure and performance qualification can be done by a strict welding system control with proper fits, filler metal, control of parameters, use of a high skill welder, or autogeneous welds etc. and post weld heat treated with 100% QA/QC NDT + strain gage & leak testing and obtain similar performance attributes, then the questioner may have some relief here. It can be at least tried out with certain calculated risk.

Answer 3:

I am unaware of any code that would deny you the option to fabricate u tubes by welding. Most owner/users tend to require u bends free from welding which they typically address in their standard fabrication specs which are agreed to by the owner and fabricator prior to fabrication. In some fabrications, which utilize heavy large diameter tubes, welded return bends are the only option to meet the flattening and thinning tolerance requirements of TEMA. By TEMA requirements PWHT of the u bends is also an option, not a requirement, which should be agreed to by the owner/user and the fabricator. Cold forming of u bends may induce embrittlement or susceptibility to stress corrosion in certain materials and/or process streams. Heat treatment would alleviate such concerns.

Hydrotesting of Cryogenic Piping


Does anyone have any experience of successfully hydrostatically testing cryogenic LNG service piping? If so what methods did you employ to dry the lines before start up to prevent icing / hydrate formation during operation of the lines?

Answer 1:

As per ASME Sec. VIII ; Div1 -- Metal Temp. during Hydrotest shall be maintained at least 30F above the Minimum Design Metal Temperature but not to exceed 120F to minimize the risk of Brittle Fracture Failure during hydrotesting.

Also as per NBIC -- Metal Temperature during hydro shall not be less than 60F unless toughness characterization and simulation experimentation establishes otherwise and Maximum Temperature shall not exceed 120F.

Now before hydrotesting LNG piping has to be brought into desired temperature slowly as per certain written procedures. This can be done by slow Steam Purging with opening up of insulation pockets. But in fact there exists a fair chance that the hydrotest operation can leave some pockets of water inside piping and this traces of water if not removed i.e. if not dried out with micro-assurance (by some instrumented dew point detection principle) there can be a fair chance of hazards during next service entry of the line. Even pnuematic may cause occuled air pockets if not flushed out by some inter media and highly ensured.

Again no one will attempt or encourage to open up the entire cold insulation from the very beginning but in case any pressure drop observed during testing unless you have some suitable tracer type instrument it would be difficult to identify the exact leak locations under insulation and to take plan for corrective actions. So, as discussed with some consultants may I propose the following :- (1) It will be better here to avoid Hydrotest/Pneumatic test from test pack and just ensure design integrity and material integrity from construction stage and also ensure in-service operational integrity. (2) If at all it is a mandate you can use some inert gas or suitable hydrocarbon (liquid or gas) with a flash point less than 120F.

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