The mechanical integrity of process piping is critical to effectively manage process safety, environmental hazards, and business risks in the oil & gas, chemical, petrochemical and power industries. Operating companies seek to achieve cost-effective risk management and stay in compliance with state and federal regulations. So, how does one determine the optimum levels of inspection and maintenance for piping? The scale and complexity of the facility (thousands of feet of process piping in a typical refinery), significant costs related to inspection (insulation removal, provision of access,) variety of inspection techniques, and other factors present significant challenges in establishing a mechanical integrity strategy for piping.
These challenges are compounded by piping and process complexities, misunderstandings and underestimating the importance of piping. The reality is that many asset integrity management programs focus on pressure vessels, heat exchangers, and fired heaters without considering the piping systems as an important asset.
A process piping system failure or leakage could have a significant impact on the business due to interruptions in production, or a catastrophic effect if an explosion or fire occurs or a hazardous fluid is released.
This article highlights some of the myths, the challenges, and the good practices related to piping integrity management activities in order to help inspection and maintenance managers make the right decisions to develop cost-effective piping inspection plans without compromising the asset’s reliability or performance.
Part 1 – The Challenge
The following statements from site management illustrate the nature of the “piping integrity management challenge”:
Management: “We meet all our legal obligations”
- The primary purpose of legislation is to protect workers, the public and the environment. Legislation does not cover the risks to the business from an incident.
- In most countries, legislation does not adequately cover piping (if at all).
Management: “Inspection is done by the official third party inspector; we get a certificate for continued operation from him”
- How much piping is actually inspected?
- Does the inspector know the key hazards and vulnerabilities/deterioration mechanisms for piping, and understand the risks to the business?
Management: “We have a Risk-Based Inspection system”
Reality: In the authors’ experience with clients around the world, Risk-Based Inspection (RBI) approaches often do not adequately identify the specific vulnerabilities of piping, or translate these into effective inspection plans.
Management: “Our inspection regime complies with API 570”
Reality: This mention of API 570 (American Petroleum Institute) usually means the site has a statistical approach based on Thickness Measurement Locations (TML), in the belief that corrosion is uniform, so its condition can be determined by thickness measurements at defined locations.
Let’s look more closely at some typical myths.
Myth No.1: Pressure vessels are more important for plant safety than piping.
Reality: Contrary to what many plant personnel might think, piping is more likely to fail than a pressure vessel. Incident data from a variety of sources shows that approximately 40% of major plant losses are due to piping – the largest single cause. For example, the UK’s Health and Safety Executive Report RR672 "Offshore Hydrocarbon Release 2001-2008" revealed that piping is the most common equipment type to experience releases, together with associated equipment such as flanges and valves.
The myth may arise from the situation in most countries where legislation focuses on pressure vessels rather than piping.
Myth No.2: The requirements for managing piping are specified in legislation. So compliance with regulations is sufficient to assure the integrity of piping.
Reality: Legislation in many countries does not cover piping, or only covers certain categories of piping. For example, the European Pressure Equipment Directive applies only to the design and construction of new piping and does not apply to piping equal to or less than NPS 1 (Nominal Pipe Size in inches). In some other regions, “larger bore” piping has more focus than “small bore” piping (based on stored energy considerations). This can lead to an impression that small-bore piping is not important. However, most mechanical engineers know that many leaks involve small-bore piping because of the range of loads to which it can be subjected, its inherent vulnerability to failure (corrosion, vibration/fatigue, mechanical damage, etc.), and the sheer amount of small-bore piping in a typical facility. It is worth noting that for most process plants (even large-scale refineries) the average pipe size (based overall length) is between NPS 2 to NPS 4. There are many thousands of feet of piping in a typical process plant, and much of it is not readily accessible for inspection.
Failures of small bore piping may be regarded as “minor incidents,” but these can be early warnings of major weaknesses in management systems and plant practices. And each incident represents a potential disruption to production and places plant personnel under increased risk.