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Blogs The Notorious Corrosion Under Insulation https://ampp.mydigitalpublication.com/july-2023/page-52 Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs Elevated temperature Creep test of Metallic Material ASTM E139 is a standard method for performing elevated temperature creep testing of metallic materials under constant strain rate conditions. This procedure involves subjecting a cylindrical specimen to a constant tensile load at a specified temperature for several hours to several days, depending on the material and application. The deformation of the specimen is continuously measured using an extensometer, and the resulting data is used to determine the material’s creep properties, such as creep rate, creep strain, and time to failure, under constant loading conditions. The main objective of the test is to evaluate the creep behaviour of metallic materials at elevated temperatures and to determine their time-dependent deformation characteristics. The test results can be used to design and select materials for high-temperature applications, as well as to develop more accurate predictive models for the long-term behaviour of metallic materials under stress. The ASTM E139 standard provides guidelines for conducting the elevated temperature creep test, including specimen preparation, testing equipment, and data analysis. It also outlines the reporting requirements for test results, such as stress and strain data, test duration, and temperature. By following this standard, the consistency and reproducibility of test results can be ensured, allowing for meaningful comparisons between different materials and testing conditions. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs Home / Blogs Fractography Fractography is a technique utilized in materials science and engineering to study the surfaces of fractured materials and comprehend their failure cause and mechanism. Fracture analysis is the process of examining the fractured material surface to determine the primary cause of failure, such as design errors or manufacturing defects, to avoid future occurrences. The fracture surface is studied in a failure analysis utilizing techniques such as optical microscopy, scanning electron microscopy, and X-ray diffraction to reveal the material’s structure, composition, and fracture pattern, indicating whether the fracture was ductile or brittle and the stress concentration areas that caused the failure. Overall, fractography and failure analysis are crucial tools in improving material behaviour, enhancing their performance, and ensuring their reliability in real-world applications. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry Effect of Elevated testing on Properties of Metallic Samples GRP/GRE/GRV – what they are Asset Integrity Management – Key Principles No posts found

Blogs Quantitative Risk Assessment (QRA) using API 581 API 581 is a recommended practice document published by the American Petroleum Institute (API) that provides a quantitative risk assessment (QRA) methodology for assessing the likelihood and consequences of potential failures in pressure vessels, piping, tanks, and other equipment in the oil and gas industry. Here are the key features of API 581: API 581 provides a comprehensive and systematic approach to evaluate the risk of equipment failures by considering the likelihood and potential consequences of such failures. The document includes guidelines for establishing inspection intervals, defining damage mechanisms, determining the remaining life of equipment, and prioritizing inspection and maintenance activities. API 581 uses a risk matrix to prioritize equipment based on the severity and likelihood of potential failures. The matrix uses a numerical risk ranking system to prioritize equipment for inspection and maintenance. The document provides a framework for implementing a risk-based inspection (RBI) program, which allows for more effective and efficient use of inspection resources by focusing on higher-risk equipment. API 581 covers a wide range of equipment types, including pressure vessels, piping, tanks, heat exchangers, and other types of equipment commonly found in the oil and gas industry. The document includes detailed information on various damage mechanisms that can affect equipment, such as corrosion, fatigue, and cracking. API 581 provides guidance on the selection of appropriate inspection and monitoring techniques based on the type of equipment and the identified damage mechanism. The document emphasizes the importance of ongoing data collection and analysis to support the RBI program and improve the accuracy of risk assessments. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs PIPELINE DEFECT ASSESSMENT USING ASME B31G ASME B31G is extensively employed as a standard for assessing pipeline defects, primarily for pipelines utilized in the oil and gas industry. This standard provides a straightforward and cautious technique for appraising the residual strength of damaged or corroded pipelines. The B31G approach relies on a basic stress analysis of a pipeline containing a longitudinal crack or corrosion flaw. This method involves determining the critical flaw size, which is the largest defect size that a pipeline can handle before collapsing under applied stress. The critical flaw size is established by considering the pipeline’s diameter, wall thickness, material characteristics, and pressure and temperature during operation. After establishing the critical flaw size, the actual defect size is evaluated in comparison to the critical flaw size using a dimensionless measure known as the “severity factor.” The severity factor is a function of the defect depth-to-wall thickness ratio and the defect angle relative to the pipeline’s longitudinal axis. If the severity factor is equal to or less than 1.0, the defect is considered acceptable, and the pipeline can continue operating. If the severity factor exceeds 1.0, the defect is deemed unacceptable, and the pipeline must be repaired or replaced. It should be noted that the B31G approach is a conservative method and may result in excessively cautious assessments in certain cases. As a result, it is suggested to utilize this method together with other assessment approaches, such as finite element analysis, to obtain a more precise evaluation of pipeline defects. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs Erosion of Pipelines/Piping Pipeline erosion and fluid flow velocity are well-known to be related. A fluid that is flowing through a pipeline applies force to the pipe’s inside surface. Erosion, also known as the wear away of the pipe material over time, can be brought on by this force. The amount of erosion that takes place is significantly influenced by the fluid’s velocity. At low velocities, erosion is often not a big concern because the force the fluid exerts on the pipe is relatively minimal. Yet, the force acting on the pipe rises as the fluid’s velocity does. If the velocity is high enough, it may seriously harm the pipeline by causing erosion to happen more quickly. The precise relationship between fluid velocity and erosion is determined by a number of factors, including fluid properties (such as viscosity and density), pipeline size and shape, and pipe material properties. Higher fluid velocities, on the other hand, result in faster erosion rates. The optimum fluid flow velocity in pipelines to prevent erosion is determined by several factors, including fluid properties, pipeline size and shape, and pipe material. However, the maximum fluid flow velocity recommended to prevent erosion in pipelines is typically around 5 m/s (16.4 ft/s) for liquids and 30 m/s (98.4 ft/s) for gases. If the fluid flow velocity exceeds these recommended limits, erosion can occur at a faster rate, causing pipeline damage. High fluid velocities can also cause turbulence, pressure drops, and increased pumping costs, in addition to erosion. Engineers may use a variety of techniques to prevent pipeline erosion, such as selecting more resistant materials, modifying the shape of the pipeline to reduce fluid velocity, or using coatings or liners to protect the pipe surface. Engineers use various methods such as flow modeling and analysis, pipeline design modifications, and flow control devices such as valves and flow restrictors to ensure that fluid flow velocities are within the recommended limits. They also choose pipeline materials that are resistant to erosion and corrosion, and they conduct routine maintenance and inspections to detect and address any erosion-related issues. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs Creep Damage Creep damage refers to the deterioration of metallic samples and other materials when exposed to high temperatures and stress over extended periods. This phenomenon results in the gradual deformation and weakening of the material, ultimately leading to failure. Creep damage can be divided into three phases: Transient or primary creep: During this phase, the material undergoes initial deformation and strain rate, which progressively diminishes. The creep strain increases at a reduced rate, allowing the material to adjust to the applied stress. Steady-state or secondary creep: This phase is marked by a consistent strain rate. The material strikes a balance between work hardening and recovery processes, resulting in a relatively stable rate of deformation. Of the three creep phases, this one tends to last the longest. Accelerated or tertiary creep: In this concluding phase, the strain rate quickly escalates, causing the material to weaken considerably. The formation of microstructural defects, such as voids and cracks, can be attributed to this stage, eventually leading to the material’s rupture and failure. Creep damage is a vital concern in industries like power generation, refining, petrochemicals, aerospace, and automotive, where materials face high temperatures and stress for prolonged periods. To ensure the safe and dependable operation of equipment, engineers and materials scientists must consider creep damage when designing components and choosing materials for high-temperature applications. Material Approx. Creep Damage Temperature Range (°F) Approx. Creep Damage Temperature Range (°C) Carbon Steel (Low alloy) 800 – 1100 425 – 590 1.25Cr-0.5Mo (Low alloy) 900 – 1200 480 – 650 2.25Cr-1Mo (Low alloy) 950 – 1300 510 – 705 5Cr-0.5Mo (Low alloy) 1000 – 1350 540 – 730 9Cr-1Mo (Low alloy) 1100 – 1450 595 – 790 12Cr-1Mo (Low alloy) 1200 – 1500 650 – 815 300 Series Stainless Steel (Austenitic) 1100 – 1500 595 – 815 400 Series Stainless Steel (Ferritic) 950 – 1300 510 – 705 17-4PH (Precipitation Hardening Stainless) 1000 – 1300 540 – 705 Inconel (High nickel alloy) 1400 – 2000 760 – 1095 Hastelloy (High nickel alloy) 1400 – 2100 760 – 1145 Monel (High nickel alloy) 1200 – 1700 650 – 925 Titanium Alloys 800 – 1200 425 – 650 The creep damage temperature ranges mentioned above are approximate and can vary depending on the specific alloy composition, heat treatment, and service conditions. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found

Blogs Home / Blogs HIC, SSCC and SOHIC HIC, SSCC, and SOHIC are different types of hydrogen-induced damage that can occur in metals, particularly in steel. Here is a table comparing their characteristics: Causes Hydrogen absorbed during production, operations, or exposure to corrosive environments containing H2S Mechanism Hydrogen atoms migrate to regions of high stress, combine to form molecular hydrogen, and create pressure, leading to cracks Crack Orientation Random, stepwise pattern, typically in the direction of the metal’s rolling plane Microstructure Affected Typically affects the metal at or near the mid-thickness, following the rolling plane Prevention Proper material selection, controlling H2S levels, using low hydrogen welding techniques, and applying coatings or inhibitors Causes Exposure to sour environments containing H2S; the presence of sulfides in the steel microstructure Mechanism Corrosive hydrogen atoms react with metal sulfides, leading to the formation of cracks under the influence of applied or residual stress Crack Orientation Can be intergranular or transgranular, but often propagate in the direction of applied or residual stress Microstructure Affected Can affect any part of the metal’s microstructure Prevention Material selection, controlling H2S levels, using low hydrogen welding techniques, stress relief heat treatment, and applying coatings or inhibitors Causes A combination of hydrogen absorption and stress, often in H2S-containing environments Mechanism Hydrogen atoms collect along the planes of residual or applied stress, resulting in the development of cracks oriented parallel to the stress direction Crack Orientation Cracks are oriented parallel to the direction of applied or residual stress, often forming multiple crack layers Microstructure Affected Primarily affects the mid-thickness of the metal, similar to HIC, but can propagate deeper through the material Prevention Material selection, controlling H2S levels, using low hydrogen welding techniques, stress relief heat treatment, and applying coatings or inhibitors Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry Effect of Elevated testing on Properties of Metallic Samples GRP/GRE/GRV – what they are Asset Integrity Management – Key Principles Typical Corrosion Types Apr 2023 CORROSION RISK ASSESSMENT METHODOLOGY Fatigue Failure Unravelling the Roots: Fishbone Diagram for Root Cause Analysis The Critical Value of CTOD: Understanding Fracture Mechanics No posts found

Blogs Importance of Life Cycle Costs in Oil & Gas Industry Investment decisions: LCC analysis helps determine a project’s long-term financial viability by taking into account capital costs, operating costs, maintenance costs, and other pertinent factors. Making investment decisions and securing finance both require access to this information. Budgeting and cost management: Understanding life cycle costs makes it easier to develop budgets for various project phases and put them into action. As a result, financial risks are decreased and resource allocation is enhanced. Asset management: By determining the most economical methods for asset upkeep, replacement, and decommissioning, LCC helps to ensure effective asset management. This ensures that assets are used to their fullest potential throughout their lifespan. Risk management: Life cycle cost analysis can identify potential risks and ambiguities connected to cost overruns, scheduling delays, or market volatility. Using this information can help you create risk mitigation measures and backup plans. Environmental and social considerations: LCC analysis can take environmental preservation costs, regulatory compliance costs, and social responsibility costs into account. This makes it possible to make well-informed decisions that balance sustainability and profit. Performance benchmarking: To identify the most affordable solutions, life cycle cost analysis offers comparisons between alternative projects, technology, or methodologies. This may lead to improved project performance overall, better technology choices, and more efficiency. Making decisions: LCC provides a thorough awareness of the advantages and disadvantages of various options. Making educated decisions on design, building, operation, maintenance, and decommissioning activities requires the use of this knowledge. Tamás Hám-Szabó Founder of SAAS First – the Best AI and Data-Driven Customer Engagement ToolWith 11 years in SaaS, I’ve built MillionVerifier and SAAS First. Passionate about SaaS, data, and AI. Let’s connect if you share the same drive for success!Share with your community! Facebook Twitter Youtube Youtube In this article Corrosion Under Insulation (CUI) at a Dubai Hotel Swimming Pool The Notorious Corrosion Under Insulation Elevated temperature Creep test of Metallic Material Fractography Quantitative Risk Assessment (QRA) using API 581 PIPELINE DEFECT ASSESSMENT USING ASME B31G Erosion of Pipelines/Piping Creep Damage HIC, SSCC and SOHIC Importance of Life Cycle Costs in Oil & Gas Industry No posts found