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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 WWW.WEMTRADING.BIZ

Corrosion Under Insulation (CUI) Inspection  Inspection for Corrosion Under Insulation should be considered for externally insulated piping, including sections in intermittent service or operate at temperatures between: a) −12 °C and 177 °C for carbon and low-alloy steels; b) 60 °C and 177 °C for austenitic stainless steels; c) 138 °C and 177 °C for duplex stainless steels. Corrosion Under Insulation inspections may be conducted as part of the external inspection. If Corrosion Under Insulation damage is found during spot checks, the inspector should inspect other susceptible areas on the piping. Although external insulation may appear to be in good condition, CUI damage may still be occurring.  Nonintrusive techniques, such as real-time radiography (RTR), can help determine if any scale is present behind the insulation without removal. Other techniques, such as profile RT, pulsed eddy current (PEC), and guided wave examination can help locate damage. Removal of scale on live equipment and removal of insulation where leaks are suspected can pose a significant safety risk.  CUI damage is often quite insidious in that it can occur in areas where it seems unlikely. Considerations for insulation removal include, but are not limited to, the following:  a) history of CUI for the specific piping system or comparable piping systems; b) visual condition of the external covering and insulation, rust stains, biological growth, bulged, dented or punctured weather jacketing; c) evidence of fluid leakage (e.g. drips or vapors); d) whether the systems are in intermittent service; e) condition/age of the external coating, if known; f) evidence of areas of wet insulation; g) potential for the type of insulation to absorb/hold more water (e.g. open cell versus closed cell hydrophobic versus nonhydrophobic materials); h) low points of sagging lines; i) bottom of vertical pipe; j) proximity to equipment that could increase local humidity (e.g. cooling towers); k) area where temperature regimes are moving into and out of the CUI susceptible temperature range; l) piping components (e.g. nipples, nozzle, supports, and deadlegs) that are part of the piping system but penetrate the insulation or can transition into the CUI range. #oil #refinery #process #piping #corrosion #cui #gas #LNG #tank #vessel #safety #processsafety #learning #maintenance #inspection #API #pipeline #damage #engineering

#Casing Integrity Testing #Replacmdnt_Infltable_Packers_And_Elements Casing integrity testing involves the testing of an entire borehole via a single packer or viaa straddle packer system allowing the testing of specially selected zones. Both methods provide reliable results with the use of each system dependant on the situation. Thereliability of casing is important for many reasons including support for the drilled hole, prevents fluid loss into or contamination of production zones, provides a smooth surface for installing production equipment, allows the flow or production of oil & gas wells without leakage into the formation through the well. type of casing installed into a freshly drilled hole is dependant on downhole conditions. Steel, and in recent years PVC has become more common especially in water wells. Diameter of the well, pressures and temperatures throughout the well, high or lowpH levels (may become corrosive), Dissolved solids such as salt may also become corrosive to steel casing. Poor earthing of downhole pumps will cause rapid corrosion through electrolysis as the current finds the shortest possible path to earth (steel casing). Dissimilar metals in an electrolyte such as salt water will also cause galvanic corrosion. PVC is resistant to pH corrosion, electrolysis and galvanic corrosion. Choosing between steel or PVC is dependant of the above issues however even if the correct choice of casing was taken there still may be problems with the integrity of a borehole such as human error or unforeseen circumstances. PVC must be installed correctly to retain its integrity, this creates a problem where drillers are under strict time constraints to finish a borehole. Common problems with PVC installation are related to the joins whereby a thread and o-ring are used to seal, the o-ring may be forgotten or the thread miss-aligned. Also sealing problems occur in socket and glue joins where bad glue has been used or seating issues between the casing. Casing integrity testing with a single packer is performed by lowering a single inflatable packer to the desired depth, inflating the packer to create a seal. At the surface a bulkhead or other sealing mechanism is required. Water is then pumped down to a predetermined pressure, a leak is thereby determined by a pressure drop. Identifying where a leak is coming from is as simple as starting at the bottom of a borehole and slowly raising the packer performing tests on the way up. Straddle packer are also incorporated into casing integrity testing where two packers are lowered down a borehole with a perforated pipe creating the straddle. Thestraddle pipe length may vary with standard lengths from 1m – 6m. Once the packers have been inflated water is pumped down under pressure to the ‘straddle zone’ typically located over joins in casing and any specific leak locations as identified by downhole cameras. Source - RIPE Replacement Inflatable Packers & Elements Pty Ltd.

Is it correct? 1. How does API 570 recommend monitoring areas where Corrosion Under Insulation (CUI) is a concern, and at what temperature range is CUI most likely to occur? API 570 recommends a risk-based inspection (RBI) strategy to determine the susceptibility of piping to CUI. Inspection techniques may include visual inspection, nondestructive examination (NDE) methods like profile radiography, ultrasonic testing (UT), or real-time radiography (RTR). The temperature range where CUI is most likely to occur is typically between 25°F and 300°F (-4°C to 149°C), as this range can allow for water to be present and not evaporate quickly, thereby increasing the risk of corrosion. 2. What factors should be considered when determining the inspection interval for process piping according to API 570, and what is the maximum allowed interval? The inspection interval for process piping is determined based on a number of factors including the condition of the piping, its operating environment, the fluid service, historical data, and the results of previous inspections. Additionally, risk-based inspection (RBI) methodologies may be used to determine the appropriate intervals. According to API 570, the maximum inspection interval for a piping circuit is half of its remaining life or 10 years, whichever is less, but this can vary based on the results of an RBI assessment or if the piping operates under jurisdictional regulations that specify different intervals. 3. When an alteration or repair is performed on a piping system, what are the requirements for re-rating the system, and under what conditions can a temporary repair be left in place according to API 570? When an alteration or repair is performed, the piping system may need to be re-rated if the repair or alteration affects the pressure rating, temperature range, or service of the piping. The re-rating should be performed in accordance with the original code of construction and the requirements in API 570. As for temporary repairs, conditions for their use are typically based on the urgency of the situation, the nature of the defect being repaired, and the duration until a permanent repair can be made. Temporary repairs such as leak-sealing clamps may be left in place until the next scheduled shutdown or turnaround, but they must be monitored and should not be considered a long-term solution.

Bolts, fasteners, and thread are used in almost every industry including oil and gas, manufacturing and construction. Although a small-sized component when compared with the entire asset, bolts and the immediate areas surrounding them play an important role in ensuring the integrity of an entire structure. The non-destructive testing of certain bolts and fasteners is an essential process to ensure there are no anomalies that may pose threat to the successful construction of these structures and safe operation within the industries that rely on them. Bolts are types of threaded fasteners, mostly made from metals. Depending upon the type of metal, processes used in their manufacturing, and environmental exposure, bolts and the areas around them may be prone to flaws like cracks or corrosion. Inspection before and during use helps to ensure that flaws are detected for secure and reliable fastening. Ultrasonic testing (UT) and eddy current testing (ECT) are some of the most effective and relied-upon methods for small or large bolt, fastener and thread inspections. UT inspection uses high-frequency ultrasonic sound waves to detect anomalies in the component. Similarly, ECT inspection uses an electromagnetic field for sensing the irregularities on or near the surface. An advanced NDT instrument can: - Accurately discover minute flaws. - Detect surface and subsurface fatigue damages. - Perform bolt inspection without the need to remove the fastener. - Provide thread verification quickly. - Display 2D/3D scans to study the flaw. - Provide flexibility to inspect hard-to-reach corners. Non-destructive testing is used for bolt, fastener and immediate surface area inspection as well as thread testing across many industries for quality control and safety purposes.

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.

The #Hard Shut-In Procedure for a tripping operation on a fixed rig follows a series of crucial steps to maintain control over the well during an influx (kick) situation. Here's a breakdown of the procedure, along with additional context for each step: 1. #Position Upper Tool Joint at Table and Set Slips: - Explanation: Ensure that the drill pipe’s upper tool joint is properly positioned on the rig floor's rotary table, and then set the slips. The slips secure the drill string, holding it in place and preventing any movement during the shut-in process. - Why It’s Important: This stabilizes the drill pipe and ensures safe handling during the upcoming operations, like installing the safety valve. 2. #Install a Full Opening Drill String Safety Valve and Close It: - Explanation: Install the full-opening drill string safety valve (FOSV) onto the top of the drill pipe and immediately close the valve. This isolates the drill pipe and prevents any flow through it, which is critical to preventing uncontrolled wellbore pressure from reaching the surface. - Additional Note: The FOSV allows full-bore access, ensuring that future tools can be run through the drill string if necessary. 3. #Close the BOP (Annular or Pipe Rams): - *Explanation*: Depending on the situation and the type of BOP in use, you will close either the *annular preventer* (which seals around the drill string or open hole) or the *pipe rams* (which close around the drill pipe). - Annular Preventer: Versatile, seals around various tubulars and sizes. - Pipe Rams: Designed to seal around the specific size of the drill pipe. - Why It’s Important: Closing the BOP immediately seals off the wellbore and prevents further influx from reaching the surface. 4. #Open the Choke Line HCR Valves: - Explanation: The hydraulic choke line valves (HCR) are opened to allow communication between the wellbore and the choke manifold. This is important for controlling and circulating out any wellbore pressure later on. - Best Practice: Ensure the hydraulic system is ready, and the HCR valves are in good working order to manage any pressure safely. 5. #Verify the Choke Is Closed (If Not Positive Shut-Off, Close Downstream Valve): - Explanation: It is essential to confirm that the choke is fully closed after the shut-in procedure. If the choke does not offer a positive shut-off (full closure), then close the downstream valve to ensure the wellbore is isolated completely. - Why It’s Important: A leaking or partially open choke could allow wellbore fluids to escape uncontrollably, putting the rig and personnel at risk. Proper shutoff maintains well control and ensures that pressures can be managed later. 6. Read and Record Shut-In Casing Pressure (SICP) and Trip Tank Gain Every Minute Until Stabilized: