Inspectioneering Journal

101 Essential Elements in a Pressure Equipment Integrity Management Program for the Hydrocarbon Process Industry - Part 3

By John Reynolds, Principal Consultant at Intertek. This article appears in the September/October 2000 issue of Inspectioneering Journal.
This article is part 3 of a 5-part series.
Part 1 | Part 2 | Part 3
Part 4 | Part 5


This article continues to outline the 101 essential elements that need to be in place, and functioning well, to effectively and efficiently, preserve and protect the reliability and integrity of pressure equipment (vessels, exchangers, furnaces, boilers, piping, tanks, relief systems) in the refining and petrochemical industry. This article is not just about minimum compliance with rules, regulations or standards; rather it is about what needs to be done to build and maintain a program of excellence in pressure equipment integrity management (PEIM) that will permit owner-users to make maximum use of their physical assets to generate income. Compliance is not the key to success in PEIM; excellence is.

In parts 1&2 of the article, which appeared in the two previous issues of the IJ, I introduced the full paper and provided some background on why and how the issues were being covered. It is against that background that I continue the article with 8 more of the 101 essential elements in a pressure equipment integrity management program for the hydrocarbon process industry.

There are at least 101 essential elements to any program aimed at preserving the mechanical integrity of stationary pressure equipment, in- service, in refining and chemical plants. Each of these 101 elements may need to be prioritized by site management, basis risk or current status of each element, in order to assign resources and schedule improvements in the work processes. However, the user must keep in mind that each of these 101 elements, regardless of work priority and resource limitations, needs to be implemented effectively, continuously, in order to avoid the potential for pressure equipment incidents. In other words, it is not a matter of choosing between the 101 elements and deciding that some are important and others are not. If anyone of these 101 elements is neglected long enough, there will be a potential for incidents involving the breech of containment, and the subsequent consequences, i.e. fires, explosions, toxic releases, environmental damage, personnel exposure to hazardous substances, and business interruption.

There is no real secret to achieving success in maintaining pressure equipment integrity at a high level. It’s simply doing all the things (101 of them), that need to be done, and doing them well, day after day, without let up, regardless of what the “hot program” of the month is, or regardless of what other priorities may get in the way. We must not let other distractions get in the way of effectively executing our PEIM programs, day after day.

One more thing before I continue. You may have already noticed that I have and will use the term “effective” on numerous occasions. Webster defines it as “producing a decided, decisive, or desired result”.

And that's exactly how I use it. I've seen a lot of time, money, and motion wasted on "supposedly" doing all the things described in this paper, without really being effective. It does no good to write procedures and best practices that are not effectively implemented or adhered to. It does no good if the necessary information to do the job is not transferred effectively to those who need the information. It does little good if the following issues are just a “flash in the pan”, and then take a back seat to the next “hot rock” of the day. Watch for the word “effective” through the remainder of this article and think about what it really takes to get the desired results for each essential element. So now let’s continue with 9 more essential elements:

Thickness Measurement Accuracy and Reproducibility

Any effective PEIM program needs to have appropriate NDE thickness measuring procedures in effect to assure that data will be accurate and reasonably reproducible. Our experience indicates that appropriate digital UT procedures can yield routine reproducibility within +/- 0.010" and profile radiographic (PRT) data within 6%. Our round robin tests indicated that lack of adequate procedures and training would yield accuracy variability, routinely of 3-4 times these numbers. We prefer digital thickness data over radiographic or CRT ultrasonic data because of better accuracy, less chance of reading error, speed, simplicity and cost. Without accurate data, much time and money is lost on rework and inspections that are more frequent than necessary, let alone the potential for something failing prematurely from inaccurate data. We now provide 12 hours of training and a hands-on examination for all our inspectors (company and contract) doing UT and PRT thickness measurements.

Is your thickness data accuracy good enough to allow your inspection data management program to function well, providing you with accurate inspection schedules for equipment that is subject to corrosion?

Small Bore Piping (SBP) Inspection

SBP cannot be ignored. Though the failure of SBP is not as likely to lead to a large consequences, when compared with larger primary piping, numerous experiences have been reported where the failure of SBP led to big reliability impacts (process unit shutdown) and to large fires, when secondary effects of the ensuing fire caused the failure of other larger pipe and vessels. A decade ago, a US refinery had a major incident, where a hydroprocess reactor toppled in the ensuing fire, after a one inch line failed. Not long ago, another major fire occurred at a refinery when a 3/4" tube in a hydroprocess unit ruptured. SBP that is part of primary piping systems should be included in the same program as the primary piping. SBP that is secondary piping (can be valved off without affecting production) should have piping inspections scheduled basis risk assessment.

Do you track and monitor your higher risk SBP in your process units?

Critical Check Valves

Swing check valves that are critical to process safety and reliability should also be inspected at appropriate maintenance opportunities to ensure that the flapper is free to move and not excessively worn. It’s also important to assure yourself that the shaft design of critical check valves is of a type that will prevent stem blow out if pins or keys fail. I know of a multi-hundreds of million dollar chemical plant fire that was caused when inadequate design of a check valve shaft resulted in it being blown out of the check valve when a small pin failed. The flapper stop should also be checked to assure that it is not worn or damaged.

Are all your critical check valves identified and scheduled for inspection and maintenance; and do you know if your check valves all have a fail safe design for their shafts?

Material Degradation Risk Management

A systematic process should be in place to assure that asset managers, unit process engineers, maintenance and operating personnel are not only aware of, but also involved, in the most important material degradation issues that are of concern in each process unit. The corrosion engineer and/or inspector should not be the only ones concerned about or aware of the material degradation issues. Risk based prioritization and decision-making are useful work processes for dealing with issues that could cause the failure of construction materials in pressure equipment. A multi-functional team of key stakeholders should conduct the risk based prioritization and decision making analysis, so that PEIM issues end up being properly prioritized with all other “hot rocks” of the day.

Is there a real multi-functional effort at your plant to work together, in a shared ownership environment, on pressure equipment integrity threats?

Corrosion Under Insulation (CUI)

CUI is often an out-of-sight, out-of- mind type of insidious problem until the first CUI failure shuts down an operating unit and/or causes a safety incident or near miss. Not long ago, we had an unscheduled hydrocracker outage due to a CUI leak in a light hydrocarbon reflux line, which occurred soon after the completion of a successful unit turnaround. In another plant, an operator was severely burned when CUI on an exchanger drain nipple caused a blow out and fire. An effective management program needs to be in place to prevent CUI with appropriate insulation maintenance for susceptible systems. Likewise, an effective inspection program needs to be in place where insulation management has been lacking or the age of susceptible equipment means that CUI is likely to be present. CUI corrosion rates are typically in the 10-20 mils per year range, but can be up to 40+ mils per year in some of the worst CUI environments. That means that a lot of susceptible piping and vessels may be nearing failure in 15-25 year old plants. API 570 provides good guidance on CUI inspection. Don’t make the mistake of treating potential CUI problems as just a low probability, reliability issue; as CUI failures have also led to numerous safety incidents. And don’t ignore the potential for corrosion under fireproofing (CUF) on vessel and column skirts. Recently, a light hydrocarbon sphere toppled to the ground during hydrotesting, when CUF caused the legs to weaken substantially.

Do you have an effective CUI/CUF inspection program; and more importantly, a CUI prevention program on equipment and piping susceptible to CUI?

External Corrosion Prevention

In addition to CUI, a lot of bare and buried piping can be susceptible to external corrosion, where paint and coating systems have not been adequately maintained. Not too long ago, there were two separate, fatal accidents on the gulf coast when high pressure light hydrocarbon pipelines ruptured. The failures resulted from external corrosion on the pipelines and the ignition occurred in both cases when someone drove a vehicle into the escaping vapor cloud. Maintaining external paint systems on piping costs only 10-20% of what it would cost to have to start over with grit blasting once the paint systems deteriorates badly, i.e. you get beyond the slight “rust blooming” stage. Clearly there’s more to maintaining paint and coating systems than just ascetics, but ascetics can be important too. My observations over the last three decades tell me that the better a plant looks, the more employees care about the important things in the plant. Junkyard workers are usually not very productive or effective. This is also an issue of compliance within the USA. If you are not aware of CFR 1910.106, Flammable and Combustible Liquids, (c) (5), it reads: “All piping for flammable and combustible liquids, both aboveground and underground, where subject to external corrosion, shall be painted or otherwise protected.” That’s fairly clear. Do you maintain the paint/ coating systems on your piping and pressure vessels so that you have a low risk of experiencing leaks or safety incidents from external corrosion?

Hot Spots

Hot spots are not an infrequent occurrence in furnaces and refractory lined equipment; and, as such, it’s important that we know how to monitor and evaluate them. Just a couple of years back, a Canadian refinery suffered a fatality when a hot spot on a charge heater led to a tube rupture. As it turns out they knew about the hot spot, but misdiagnosed it as glowing scale on the tube. Another plant just recently suffered a blow out and fire on a refractory lined effluent transfer line on a steam-methane reformer heater. The refractory had failed, leading to the hot spot and eventual line rupture because it went undetected. An effective thermography inspection program can effectively detect and measure hot spots. Temperature sensitive paint can serve as a warning when refractory failure has occurred on the inside diameter. Once detected, it’s very important that experienced, knowledgeable engineers and inspectors be involved in evaluating and monitoring the hot spot, to ensure that blow out conditions don’t develop. Equipment can operate reliably for long periods of time, with adequate, temporary, hot spot mitigation measures in place, if they are properly designed and implemented.

Do you have effective hot spot monitoring and evaluation procedures in place to make sure you don’t suffer a surprise rupture of equipment with a hot spot?

Bull Plugs

I’ll bet everyone knows of incidents caused when threaded bull plugs (pipe plugs) came loose from drains, vents, valves, etc., and led to hydrocarbon releases and fires. This is another of the “small aspects” of our business that needs to be managed well, day after day, in order to avoid reliability and safety incidents. I’m reminded of a significant fire that occurred about a decade ago in a French refinery when a drain plug on the bottom of a pump casing backed out in service leaving a 3/4" hole for hot hydrocarbon to escape. Another fire and injury occurred just last year, when someone bumped a high point bleeder, causing the loose bull plug to fall out. Sometimes these plugs just come loose from service vibrations; sometimes the threads corrode, sometimes the wrong material is installed because the PMI program does not extend to bull plugs.

Do you have an effective preventive maintenance and control program for bull plugs, to minimize the potential for them blowing out, at your facility?

Fatigue Failures

Like bull plugs, fatigue failures in small bore piping (SBP) can lead to reliability and safety incidents, with sudden failures. But unlike bull plugs, we usually have some warning that something is wrong; and therefore have a chance to prevent the failure. If operators and others who are around operating equipment (especially machinery) on a daily basis will report vibrating piping or unsupported, overhung weight on SBP, to inspection or engineering, appropriate analysis and mitigation can be implemented. Early in the life of a plant, or a plant change, it’s not unusual to experience vibration. That’s the time to do something about it. No one should treat vibrating piping as common place, as it may take only days to break, or it may take years; but the results will be the same. Fatigue failures have to be prevented; as we cannot inspect for them. It’s a rare day when we find a fatigue crack before it results in a through wall crack or worse yet, pipe separation. I recall a chemical plant that had a full line separation on a two-inch pipe, which released 20,000 pounds of light hydrocarbon in just minutes. They were really lucky; no ignition, this time. Another plant was not so lucky, as they had immediate ignition in the mid-90’s when a 4 inch nozzle fell off a column in service. It just had a valve and a blind flange attached to it. These two cases involved austenitic stainless steel, which seems to be even more susceptible to fatigue failures than steel and it’s alloys.

Are the operators in your plant sensitive to vibration problems on piping systems (especially branch connections) and do they know what can happen to them personally, if vibration leads to fatigue cracking?


In parts 1-3 of this article, I have covered the first 27 of the 101 essential elements of a pressure equipment integrity management program for the hydrocarbon process industry. In the next few articles, I will continue to enumerate what I believe are the other 74 essential elements, including such topics as: boxing of leaks, on-stream inspections, hydrotesting safety, flange gasket selection, fitness-for- service analysis, cast iron, heat tracing in safety systems, soil-to-air corrosion of buried piping interfaces, and much more. If you have some thoughts on what you have just read or suggestions for inclusion in the remaining 73 elements, let me hear from you through the IJ at

Continue to the next article in this series.

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