Inspectioneering Journal

Effective End of Useful Life Strategies for Pressure Equipment

By Greg Alvarado, Chief Editor at Inspectioneering. This article appears in the July/August 2015 issue of Inspectioneering Journal.


Asset managers need to know when repairs and replacement are required for many reasons, including safe operation, accurate budgeting, replacement planning, and on-going reliability. When predicting design life based on a simple, linear corrosion rate versus remaining thickness, metallurgical degradation, or crack propagation rates are often not accurate or realistic. Even if the models are good, things change (e.g. feed chemistries, operating practices, operating conditions, etc.). Inspections are performed to measure the impact of these changes and increase the accuracy of the end of design life prediction.

As Inspectioneering Journal readers know, pressurized process plant equipment is built to an equipment design and construction code such as ASME Section VIII Div. 1 with a 3.5:1 or 4:1 safety margin, or to alternative rules such as ASME Section VIII Div. 2. Equipment is designed to operate safely and reliably according to anticipated operating conditions such as temperatures, pressures, corrosion rates, fatigue cycles, and so forth for a set period of cycles and/or time. This time takes equipment degradation rates into consideration. In reality, equipment is rarely always operated according to design.

For example, the design package for a vessel in fatigue service, such as a pressure swing absorber, will normally include the number of fatigue cycles the vessel was designed for through end of life. While the design package may show the limit at 1,000,000 cycles, it may be perfectly safe to continue operating the vessel beyond that point. Similar logic could be used for corrosion versus the design T-min, again versus the design code/safety margin. Another scenario is heater tube remaining life evaluation. These three scenarios are often the norm.

Regulators are considering imposing the practice of inherently safe design (ISD) on our industries. This is a direct result of recent high profile equipment failures in the industry. This article is not aimed at the topic of ISD, although it should offer some helpful insight and provide some education for regulators, insurers, and owner operators when framing the practice. It could help owner-operators with ideas on methodology to feel more comfortable with the safety case, should it be required. It stands well on its own, one way or the other.

The two primary subjects covered in this article are risk-based inspection (RBI) and fitness-for-service (FFS). The latest editions of API (American Petroleum Institute) RP 581, API RP 580, and API RP 579-1 are widely considered to be representative of industry best practices for these subjects.  For this article, readers should know that under API RP 581, in the POF (probability of failure) part of the risk calculation, t-min may either be calculated as the design basis, or any appropriate input the user decides upon (e.g. FFS Level 2, FFS Level 3, etc.). API RP 580 is the overarching document that is much more brief and high level that RP 581.  API RP 580 details the “what to do at a minimum for a credible RBI analysis and program;” whereas API RP 581 is the “how to do it” document.

Once the equipment is commissioned and placed into service, the construction code may not dictate when inspections, repairs, or replacement are necessary, unless the jurisdiction, insurer or owner operator  require it as part of their mechanical integrity program. Standards and codes like API 510, API RP 581, API 579-1/ASME FFS-1 can take over and provide guidance for inspect, run, repair, or replace decision-making. So these codes and standards play a key role in making end of life decisions for pressure equipment. This article brings them together in concert.

Inspection usually plays a huge role in end of useful life calculations. Inspections are regularly performed to gather more information about the current damage state of the equipment and to validate or correct the anticipated damage progression rate. Armed with this information, the owner can make decisions about:

  • The next required inspection date (typically based on an inspection code like API 510/570/653), which allow RBI in lieu of traditional approaches

  • Options to mitigate or lessen the damage rate (e.g.  installing liners, coatings, chemical inhibition, adjusting operating conditions, etc.)

  • Anticipated repair/replace date

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Comments and Discussion

Posted by mahendra kumar rastogi on August 29, 2015
It is a great article. regards, mahendra Log in or register to read the rest of this comment.

(Inspectioneering) Posted by Greg Alvarado on September 1, 2015
Thank you Mahndra! It may help to know that my... Log in or register to read the rest of this comment.

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