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🔲 API 571, titled "Damage Mechanisms Affecting Fixed Equipment in the Refining Industry," provides guidelines and recommendations for the identification and assessment of damage mechanisms in process equipment such as pressure vessels, piping, and tanks in the refining industry. It is a practical guide that helps engineers and inspectors understand and manage the various damage mechanisms that can occur in these assets. 🔲 The API 571 standard covers a wide range of damage mechanisms, including corrosion, cracking, fatigue, embrittlement, erosion, and others. It provides information on the causes, characteristics, and inspection methods for each damage mechanism, as well as guidance on how to assess the severity and remaining life of equipment affected by these mechanisms. 🔲 Here are some key points and topics covered in API 571: 1️⃣ Damage Mechanism Categories: The standard categorizes damage mechanisms into various categories such as general, localized, high-temperature, and environmentally assisted cracking, as well as other types of damage. 2️⃣ Damage Mechanism Descriptions: API 571 provides detailed descriptions of each damage mechanism, including its causes, contributing factors, typical locations, and inspection methods. 3️⃣ Inspection and Monitoring: The standard offers guidance on inspection techniques and monitoring strategies to detect and assess damage mechanisms effectively. It covers non-destructive testing (NDT) methods, visual inspection, thickness monitoring, and other relevant techniques. 4️⃣ Damage Mechanism Evaluation: API 571 provides information on evaluating the severity of damage mechanisms based on factors such as cracking length, corrosion rate, remaining wall thickness, and other relevant parameters. 5️⃣ Mitigation and Control: The standard offers recommendations for mitigating and controlling damage mechanisms, including material selection, corrosion inhibitors, protective coatings, maintenance strategies, and inspection intervals. 6️⃣ Fitness-for-Service (FFS) Assessment: API 571 outlines the principles of performing a fitness-for-service assessment, which involves evaluating the structural integrity and remaining life of damaged equipment, considering factors such as the damage mechanism, operating conditions, and inspection results. 🔲 It's important to note that API 571 is a reference document and should be used in conjunction with other industry standards and practices, such as API 570 (Piping Inspection Code) and API 510 (Pressure Vessel Inspection Code), to ensure comprehensive assessment and management of equipment integrity. 🔲 The API 571 standard is regularly updated, so it is advisable to consult the latest version of the document for the most up-to-date information and guidelines on damage mechanisms in the refining industry.

🔲 API 571, titled "Damage Mechanisms Affecting Fixed Equipment in the Refining Industry," provides guidelines and recommendations for the identification and assessment of damage mechanisms in process equipment such as pressure vessels, piping, and tanks in the refining industry. It is a practical guide that helps engineers and inspectors understand and manage the various damage mechanisms that can occur in these assets. 🔲 The API 571 standard covers a wide range of damage mechanisms, including corrosion, cracking, fatigue, embrittlement, erosion, and others. It provides information on the causes, characteristics, and inspection methods for each damage mechanism, as well as guidance on how to assess the severity and remaining life of equipment affected by these mechanisms. 🔲 Here are some key points and topics covered in API 571: 1️⃣ Damage Mechanism Categories: The standard categorizes damage mechanisms into various categories such as general, localized, high-temperature, and environmentally assisted cracking, as well as other types of damage. 2️⃣ Damage Mechanism Descriptions: API 571 provides detailed descriptions of each damage mechanism, including its causes, contributing factors, typical locations, and inspection methods. 3️⃣ Inspection and Monitoring: The standard offers guidance on inspection techniques and monitoring strategies to detect and assess damage mechanisms effectively. It covers non-destructive testing (NDT) methods, visual inspection, thickness monitoring, and other relevant techniques. 4️⃣ Damage Mechanism Evaluation: API 571 provides information on evaluating the severity of damage mechanisms based on factors such as cracking length, corrosion rate, remaining wall thickness, and other relevant parameters. 5️⃣ Mitigation and Control: The standard offers recommendations for mitigating and controlling damage mechanisms, including material selection, corrosion inhibitors, protective coatings, maintenance strategies, and inspection intervals. 6️⃣ Fitness-for-Service (FFS) Assessment: API 571 outlines the principles of performing a fitness-for-service assessment, which involves evaluating the structural integrity and remaining life of damaged equipment, considering factors such as the damage mechanism, operating conditions, and inspection results. 🔲 It's important to note that API 571 is a reference document and should be used in conjunction with other industry standards and practices, such as API 570 (Piping Inspection Code) and API 510 (Pressure Vessel Inspection Code), to ensure comprehensive assessment and management of equipment integrity. 🔲 The API 571 standard is regularly updated, so it is advisable to consult the latest version of the document for the most up-to-date information and guidelines on damage mechanisms in the refining industry.

pipe schedule and hydraulic calculations according to NFPA13

Many pipe support designs such as resting or mechanically fastened supports allow water to collect between the support and the pipe surface, and thus create an ideal environment for crevice corrosion. In some cases, galvanic corrosion can also be a cause for concern. Even though both the support and pipe material are steel, there may still be a small enough potential difference to generate a corrosion cell. Welded supports offer a solution to this problem; however, construction and future inspection costs may make this option undesirable. Identifying corrosion at support locations is difficult as the support itself commonly conceals the pipe surface in the region of concern. https://lnkd.in/gY2vvyr7 #ndttesting #ndtinstruments #pautprobes #probes #customprobes #corrosion #ectane3 #lyftpro #lyftgo #tubepro6 #Sonyks #SwiftUT #perpetual #ndtsoftware

API 572 latest fifth edition November 2023 provides unique optimistic approach for inspection of vessels/towers/columns/Exchangers as compare to 4th edition Dec 2016. New edition linked API 510, API 571 API 580, API 970, API 583,API 584,API 2217A and provides a unique document/data under single book. Comparing fourth edition vs fifth edition fourth edition focuses more on design & material construction while fifth edition added some depth knowledge to each technique and detail internal inspection. No of chapter in latest edition increased to 14 added some additional information on repair,re rating,fit for service, repairing vessel degradation and inspections followed by action on inspection finding. Inspection of CUI consideration for austenitic stainless steel is updated to 140 F and 350 F in previous edition was 140 F to 400 F. And inspection of boot (where water or unwanted fluid collected and removed). In latest edition chapter 4 is linked with annex B and detail data is added related to towers internal inspection. Chapter 7 includes newly added IOW & Newly commissioned vessels.Inspection of flanged joints, Precautions regarding confined space entry.Damage mechanisms, selecting inspection activity, fixed interval,and detail discussion on internal inspection and specific Ndt to evaluate result.Number of damage mechanisms picked from API 571 provided detail scenarios where applicable. API new editions interlink all codes and latest editions contribute in achieving more accurate inspection results. Latest edition of 510 and 572 provides a great approach for increased safety of static equipment.

Let me share a little secret 🙈 Do you know how important surface preparation is when it comes to coatings in corrosion control? As a matter of fact, your corrosion control procedures starts from the surface preparation. No coating will perform well on a poorly conditioned surface as the preparation is vital in treating steel surfaces prior to coatings or linings. What stages do you consider in surface preparation? see below;👇🏾 ✅ Assess the condition of the surface to determined the extent of treatment and preparation that will be sufficient ✅ For newly fabricated steel, remove mill scales and all visible rusts. For previously coated steel, remove all old failed coatings to ensure effectiveness of the new coat ✅ Remove surface contaminants such as visible dirts, oil and salt ✅ profile the surface to ensure anchorage of the coating ✅ carry out test to check for surface cleanliness, surface profile, salt contamination, oil and dust to confirm they are within permissible limit ✅ confirm that welded areas are without defects that can affect the effectiveness of the paint ✅ prime the surface to shield the surface from its environment The more thorough the surface preparation is, the more effective the coating will be. It directly influences the adhesion of the coating on the substrate and the subsequent protection it is meant to provide on the steel. It is the secret for every successful coating. No two ways! Lets talk when you have a coating need, I am your one stop professional for everything coatings can do. I offer technical advices, proffer coating solution, inspect for conformity and see to the success of the project. Follow Nonye, for more insightful updates on project management, corrosion control, coating solutions and self development #corrosioncontrol #coatingsolutions #surfacepreparation

Corrosion at Pipe Supports Corrosion at pipe supports is one of the leading causes of plant process piping failure. It is a common conception that metal-to-metal contact coupled with water entrapment is the major cause of corrosion at these points.  1. Water is trapped: The very nature of the supports allows water to be held in contact with the painted pipe surface as well as the paint on the support element. 2. The paint system fails: Even if the paint on the pipe and support beam are perfect, the paint system is designed for atmospheric exposure. The longer the paint surface is continuously exposed to water, the more it softens. As the pipe paint softens, it is inevitable that the steel substrate will be directly exposed to the water. 3. Corrosion is initiated: The small area of steel now exposed to oxygenated water starts to corrode. 4. Corrosion undercuts paint film: The initial corrosion soon undercuts and spreads. Soon the whole support area is bare steel. 5. Crevice corrosion starts: From this point on, the crevice corrosion driven by differential aeration takes over from the general corrosion mechanism that initiated the corrosion. As corrosion products build, they further restrict oxygen diffusion and the oxygen concentration gradient gets steeper. Pitting now becomes the main problem with corrosion rates accelerating by an order of magnitude. 6. Pipe fails - If the inspection program is not set up to detect this mostly concealed wall loss, the pipe will fail. Case Study:  In 2009, there was a sudden and large hydrocarbon release from a main process pipe in the Ethylene Unit at the Sunoco Marcus Hook, Pennsylvania Refinery. The release found an ignition source at an operating process furnace within 2 seconds, resulting in a fire. Seven other process lines within the pipe rack in the vicinity of the initial release ruptured from short-term overheating within the first 10 minutes. Fire fighting and process isolation efforts brought the fire under control, but it continued to burn for18 hours while process systems depressured. The initial pipe rupture on the 10” process gas line was determined to be from external corrosion at the bottom of the pipe. A localized area of corrosion resulted from the presence of a steel sleeve under the pipe where it crossed over the pipe support. The presence of this sleeve could enable moisture to be trapped within the crevice space between the sleeve and pipe. A crevice between two metal components would create a localized galvanic corrosion cell, with the potential to increase the expected corrosion rate significantly. Within the crevice area the corrosion was significant, with the physical metallurgical examination showing that 90% of the metal thickness had corroded away in the proximity of the failure area. Source:https://lnkd.in/grmr7dr8 #corrosion #fire #pipe #desing #refinery #oil #gas #support #processsafety #safety #metallurgical #examination

Welded Pipe Service Life and Influencing Factors 1.Service life of welded pipe: Welded pipe is a pipe material usually used to transport liquids, gases and solid particles. It has good pressure resistance, corrosion resistance, sealing and other characteristics, so it is widely used in various fields such as industry and construction. However, the service life of welded pipes is limited, which is roughly around 10-20 years. The specific evaluation can be based on environmental conditions, working conditions, welding processes, and product quality. 2.Factors affecting the service life of welded pipes: Environmental conditions: The environment in which the welded pipe is located has a great impact on its service life. If the welded pipe is exposed to moisture, acid or alkaline environment for a long time, corrosion will occur, thus reducing its life. For example, salt spray in the marine environment will greatly reduce the service life of welded pipes, while a dry, pollution-free environment is conducive to the care and maintenance of welded pipes. Therefore, when installing welded pipes, the selection should be based on environmental conditions and corresponding anti-corrosion measures should be taken. Working conditions: The service life of welded pipes will be different under different working conditions. If it is frequently subjected to shock, vibration, impact, etc. during use, its fatigue damage will be accelerated and its service life will be shortened. Therefore, welded pipes that have been affected by these factors for a long time should be regularly inspected or replaced. Welding process: Welding process is one of the key factors affecting the service life of welded pipes. Different welding methods (such as ERW pipes) and processes have different effects on weld quality, strength and corrosion resistance. If the weld is not strong, it will affect the service life of the welded pipe. Therefore, appropriate welding methods should be selected during welding to ensure that the weld is strong. Quality of welded pipe: The quality of the welded pipe itself is also an important factor affecting its life. If the quality of the welded pipe selected is not good and cannot meet the design requirements, the service life of the welded pipe will be shortened. Therefore, when purchasing welded pipes, you should choose high-quality products and pay attention to check whether their quality and materials meet the standards. To sum up, when using welded pipes, we should choose appropriate products and welding processes, and strengthen pipeline care and maintenance to extend the service life of the pipeline, ensure the safety and stability of project operation, and reduce the cost of repair and replacement. #pipe #PMC #manufacturing #weldedpipe #pipecoacting For more, visit: www.permanentsteel.com or Contact E-mail:daisy@permanent-steel.com Whatsapp:0086-18674543075(WeChat)

𝐂𝐨𝐫𝐫𝐨𝐬𝐢𝐨𝐧 𝐔𝐧𝐝𝐞𝐫 𝐈𝐧𝐬𝐮𝐥𝐚𝐭𝐢𝐨𝐧 (CUI) is an increasingly important problem. Most air‐exposed insulated piping and vessels are covered with porous insulation that is protected from moisture by sheet metal covering. Figure 3.16 shows the corrosion locations identified by a major operator. Figure 3.17 shows seams in the jacketing around insulated piping. The seams should be located near the bottom (6 o’clock location) so that any moisture can drain from inside the jacketing. The two seams shown in this figure are at 9 and 11 o’clock locations where moisture can enter but cannot drain out of the system. Location C shows where the jacketing has been removed to allow placement of the piping on structural supports. Many large petrochemical companies consider any insulated pipe a potential risk for CUI because it is unlikely that the pipe will stay dry over the 20‐ to 30 year required inspection cycle. Breaks in the weather barrier jacketing usually occur at joints and allow water into the insulation. This water can leach contaminants from the insulation, which are then concentrated and deposited on hot surfaces. This can eventually lead to SCC of hot stainless steel surfaces, especially with insulations containing soluble chloride salts. Figure 3.18 shows mechanical damage on the outside jacketing, which will allow rain or other moisture to enter the enclosed space around the piping and cause corrosion. CUI is hard to inspect, and it is important to conduct these inspections on a frequent basis. It is also important to replace the weather barriers after the inspection. In addition to the proper design of moisture shields and draining for insulated piping, many operators have adopted the practice of always coating the carrier piping with an immersion grade coating. It is also important to provide inspection capabilities for insulated piping. This is becoming an increasingly important consideration as more and more subsea pipelines are insulated to maintain noncorrosive temperatures on the inside of pipelines and gathering lines that would otherwise quickly cool to the temperatures of the ambient seawater environments. CUI is difficult to detect, and the use of infrared inspection cameras is one means of trying to locate places where moisture is accumulating and temperatures are different than elsewhere on nearby piping (Figure 3.20). It is important that all personnel working around insulated piping should be encouraged to report indications of leaks. Figure 3.23 shows moss growing where moisture is leaking out of the insulation jacketing. If this moisture indication had been reported, CUI on the crude oil piping might have been detected before it became serious.