管道腐蚀的英文文献
材料腐蚀与防护英文介绍范文
材料腐蚀与防护英文介绍范文Materials Corrosion and Protection.Materials corrosion is a natural process that occurs when metals or other materials are exposed to the environment. This process can lead to the degradation of the material, resulting in its failure. Corrosion can be caused by a variety of factors, including exposure to moisture, oxygen, acids, and bases.The rate of corrosion can be affected by a number of factors, including the type of material, the environment in which it is exposed, and the presence of protective coatings. Some materials are more resistant to corrosion than others. For example, stainless steel is more resistant to corrosion than carbon steel. The environment in which a material is exposed can also affect the rate of corrosion. For example, materials that are exposed to salt water are more likely to corrode than materials that are exposed to fresh water. The presence of protective coatings can alsoslow down the rate of corrosion. These coatings can act as a barrier between the material and the environment, preventing the material from coming into contact with the corrosive agents.Corrosion can have a significant impact on the performance and lifespan of materials. For example, corrosion can lead to the failure of metal components in bridges, buildings, and other structures. It can also lead to the failure of pipes, tanks, and other vessels that are used to store or transport fluids.There are a number of methods that can be used to protect materials from corrosion. These methods include:Using corrosion-resistant materials: Some materials are more resistant to corrosion than others. For example, stainless steel is more resistant to corrosion than carbon steel.Applying protective coatings: Protective coatings can act as a barrier between the material and the environment,preventing the material from coming into contact with the corrosive agents.Using cathodic protection: Cathodic protection is a process that uses an external electrical current to protect a metal from corrosion.Using sacrificial anodes: Sacrificial anodes are made of a metal that is more reactive than the metal that is being protected. The sacrificial anode corrodes instead of the protected metal.The best method of corrosion protection will depend on the specific application. It is important to consider the type of material, the environment in which it will be exposed, and the desired level of protection.Corrosion and the Environment.The environment can have a significant impact on the rate of corrosion. Some environments are more corrosive than others. For example, materials that are exposed tosalt water are more likely to corrode than materials that are exposed to fresh water. The presence of pollutants in the environment can also increase the rate of corrosion.The following are some of the factors that can affect the corrosiveness of the environment:Temperature: The rate of corrosion generally increases with increasing temperature.Humidity: The rate of corrosion generally increases with increasing humidity.Salinity: The rate of corrosion generally increases with increasing salinity.Acidity: The rate of corrosion generally increases with increasing acidity.Pollutants: The presence of pollutants in the environment can increase the rate of corrosion.Corrosion Protection.There are a number of methods that can be used to protect materials from corrosion. These methods include:Using corrosion-resistant materials: Some materials are more resistant to corrosion than others. For example, stainless steel is more resistant to corrosion than carbon steel.Applying protective coatings: Protective coatings can act as a barrier between the material and the environment, preventing the material from coming into contact with the corrosive agents.Using cathodic protection: Cathodic protection is a process that uses an external electrical current to protect a metal from corrosion.Using sacrificial anodes: Sacrificial anodes are made of a metal that is more reactive than the metal that is being protected. The sacrificial anode corrodes instead ofthe protected metal.The best method of corrosion protection will depend on the specific application. It is important to consider the type of material, the environment in which it will be exposed, and the desired level of protection.Conclusion.Corrosion is a natural process that can have a significant impact on the performance and lifespan of materials. However, there are a number of methods that can be used to protect materials from corrosion. By understanding the factors that affect corrosion, and by using the appropriate protective measures, it is possible to extend the life of materials and reduce the risk of failure.。
金属给水管道腐蚀现状及研究进展
金属给水管道腐蚀现状及研究进展周 韬(广东珠海市规划设计研究院,珠海519002)摘 要: 介绍了国内外关于城市金属给水管道腐蚀的研究现状及进展,着重阐述了输配水系统中金属管道的腐蚀特性、主要危害及控制措施。
关键词: 供水管网; 金属管道; 腐蚀; 水质Research and Development of Corrosion of Metallic Pipe in WaterDistribution SystemZHOU Tao(Z huhai I nstitute of Urban Planning and Design,Zhuhai519020,China)Abstract: T his paper introduced the progress and current studies of corrosion of metallic pipe in water distributio n sys-tem.M oreover it emphatically expounded the character,main hazard and control methords of co rrosion of metallic pipe. Key words: w ater distributio n sy stem; metallic pipe; cor ro sion; water quality 近些年来,随着水处理技术与工艺的不断进步与完善,城市水厂供水水质通常已能达标,但是自来水在管网输配过程中,往往由于管网腐蚀等原因发生“二次污染”,水质出现不同程度的下降,严重时出现用户水质指标超标以及管网“红水”、“有色水”、“黑水”等现象,对人民生活及工业用水的安全和正常使用造成严重影响。
因此,在饮用水工业中,管道腐蚀长期以来都是改善和提高用户水质的一个重大瓶颈问题,受到各国的重视[1]。
在城市供水领域中,金属管道作为主要给水管材之一已经应用了几个世纪,根据统计,我国目前90%以上的供水管道是铸铁管、钢管,近几年新建的给水管道仍有85%采用金属管道。
油田工艺管道腐蚀与防腐措施研究
技
Abstract: Oil, natural gas, oil-bearing sewage and high-pressure water are the main transportation
术
media in the oil field process pipeline, including acid, Alkali, salt and other impurities. Oil and gas
由于腐蚀给油田工艺管道的安全运行带来严重危害，如腐蚀穿孔引起油、气、水的跑、冒、滴、
漏造成的经济损失，对土壤、地下水、空气等造成环境污染，火灾、爆炸引起的人员伤亡等。因
此，研究油田工艺管道内、外腐蚀的机理，有针对性的提出相应的防腐措施，延长管道的使有寿
命，具有重要意义。
关键词：工艺管道 腐蚀 机理 措施
corrosion of oil field process pipeline and put forward corresponding anti-corrosion measures to prolong
the service life of pipeline.
Key words: process piping; corrosion; mechanism; measures
[4] 杨铠瑞. 油田注水管道的腐蚀现状及防腐策略[J]. 化工设计通 讯, 2018, 44(04): 25+143.
[5] 李清作. 浅谈注水管道腐蚀因素及涂层保护的应用[J]. 中国石 油和化工标准与质量, 2012, 32(07): 230.
[6] 马钢, 白瑞. 工艺管道腐蚀与防护研究进展中外能源, 2018(01). [7] 熊丹, 赵杰, 顾艳红, 李馥钊. 长输油气高强管线钢的腐蚀研究
国外油套管腐蚀问题的研究动态
国外油套管腐蚀问题的研究动态长庆石油勘探局博士后科研工作站韩勇赵业荣【摘要】本文根据1997－2002年NACE年会论文综述了国外油套管腐蚀问题的研究动态,以供大家参考。
1、CO2腐蚀的预测与控制（1～11）Marina Cabrini研究了油气井条件下的CO2腐蚀预测，并对井下实例进行了分析(图1)。
井下的CO2腐蚀是局部腐蚀，与碳酸盐地层有关，可行成FeCO3/CaCO3保护膜。
现有的腐蚀模型不能预测局部腐蚀。
Rolf Nrbory综述了油井与管线CO2腐蚀模型的研究现状，已有16种CO2腐蚀预测模型。
并讨论了PH值、FeCO3膜、油水比、流体流动模型及H2S等主要影响因素。
E.Dayalan 研究了FeCO3成膜条件下CO2腐蚀的预测问题，建立了相应的计算机模拟程序。
D.A.Eden和A.Etheridge研究了CO2腐蚀控制的电化学监测，并与其他方法进行了比较。
J.F.Chen用改进的电化学噪声技术进行点腐蚀的监测，提出了今后在线监测的途径（图2）。
C.A.Farina介绍了腐蚀控制的软件和腐蚀监测。
Ccarlos A.Palacios T.进行了内腐蚀预测中的模拟技术研究。
R.C.John介绍了Sweetcor公司的腐蚀分析和信息计算机系统，可根据多种参数预测腐蚀速率。
P.R.Roberge 介绍了现行腐蚀用智能系统（图3），并可能形成全球网络(附件1)。
Albertovaldes 等人研究了少量H2S对碳钢CO2腐蚀的影响，结果表明，H2S含量在未达到最大值之前，增加腐蚀速度，其腐蚀产物为FeS和Fe-C-O产物。
腐蚀速度随温度的升高而降低，其影响大于H2S地浓度影响。
S.N.Smith进行了轻微酸性环境下的腐蚀预测工作，可解释现场很少量H2S浓度下的腐蚀变化规律（图4）。
2、缓蚀剂的评价与应用（12～23）J.A.Dougherty研究了井口和管汇用水溶性和油溶性缓蚀剂的性能，其中A 种可使腐蚀速度降为0.76-0.025mm/y, B种已在19口气井（14％CO2和86％甲烷）中成功使用12年（图5）。
基于Fluent_天然气管道内腐蚀率研究
第53卷第4期 辽 宁 化 工 Vol.53，No. 4 2024年4月 Liaoning Chemical Industry April，2024基于Fluent天然气管道内腐蚀率研究王芳芳（西安石油大学， 陕西 西安 710065）摘 要：探讨了腐蚀机理，尤其是内腐蚀和外腐蚀机理。
此外，介绍了多种防腐蚀措施，其中缓蚀剂保护作为常见化学保护方法受到重点关注。
Fluent 软件作为计算流体力学工具在研究中扮演重要角色，它可模拟天然气在管道内的流动特性，并为腐蚀机理和预测模型提供输入参数。
然而，管道腐蚀问题仍面临复杂工况腐蚀机理的深入研究，新型防腐蚀技术应用和腐蚀模型精度提升的挑战。
为该领域的研究者提供了重要参考，推动管道腐蚀问题的深入解决，以期能够为天然气管道腐蚀问题的解决提供新的见解和创新解决方案。
关 键 词：天然气管道；腐蚀；防腐中图分类号：TE988.2 文献标识码： A 文章编号： 1004-0935（2024）04-0566-04在当今社会，天然气作为一种重要的清洁能源在能源供应中有着不可替代的作用。
然而，天然气管道作为天然气运输的主要通道，长期以来一直面临着严重的腐蚀问题，这对管道的安全性和可靠性构成了严峻威胁[1]。
在此背景下，对于天然气管道内腐蚀的研究显得尤为重要。
为了更好地了解和预测腐蚀的发展趋势，提高管道的安全性和可靠性，天然气管道内腐蚀的相关研究十分重要[2]。
Fluent 作为流体动力学仿真软件，具有高精度和广泛的应用性，为天然气管道内腐蚀率研究提供了强有力的工具。
随着天然气等管道腐蚀问题的日益严重，管道腐蚀的预测已成为研究的重点和热点[3]，本文围绕管道腐蚀机理、防腐蚀措施、Fluent软件应用展开。
对这些研究进行总结，以期能够为天然气管道腐蚀问题的解决提供新的见解和创新解决方案，为天然气管道的安全运行和理论发展做出贡献。
1 管道腐蚀机理1.1 内腐蚀内腐蚀由天然气管道内部因素导致，一般是由于管道内的天然气中含有腐蚀性气体以及其他杂质，主要包括硫化氢（H2S）、二氧化碳（CO2）以及水汽[4]等。
油气储运外文翻译(腐蚀类)【范本模板】
重庆科技学院学生毕业设计（论文)外文译文学院石油与天然气工程学院专业班级油气储运10级3班学生姓名汪万茹学号2010440140NACE论文富气管道的腐蚀管理Faisal Reza，Svein Bjarte Joramo—Hustvedt，Helene Sirnes Statoil ASA摘要运输网的运行为挪威大陆架（NCF)总长度接近1700千米的富气管道的运行和整体完整性提供了技术帮助。
根据标准以一种安全，有效，可靠的方式来操作和维护管道是很重要的。
天然气在进入市场之前要通过富气管道输送至处理厂.在对这些富气进行产品质量测量和输送到输气管道之前要在平台上进行预处理和脱水处理。
监测产物是这些管线腐蚀管理的一个重要部分。
如果材料的表面没有游离水管道就不会被腐蚀。
因此，在富气管道的运行过程中监测水露点（WDP）或水分含量具有较高的优先性，并且了解含有二氧化碳（CO2)和硫化氢（H2S）的水在管道中析出过程中的腐蚀机制对全面控制管道腐蚀很重要.本文将详细介绍生产监测的项目,例如讨论生产流量，压力，温度,气体组成和水露点。
一个全面的内部评估应该包括对富气管道中三甘醇（TEG)和水作用机理的详细阐述.关键词：富气管道，产品监控，内部腐蚀，腐蚀产物，二氧化碳（CO2），硫化氢(H2S），三甘醇（TEG），水露点（WDP），液体滞留。
引言从海上生产设施输送富气所使用的碳钢管线需要可靠的控制装置将水控制在气相中,以避免在管道内表面上凝结水和产生游离水。
全面腐蚀不仅仅是和腐蚀产物本身有关，沉淀产物有可能会促使一个更高的腐蚀速率［1］.液体滞留在管道中可以引起腐蚀，然而为了保证管道内部完整性仅仅评估腐蚀速度是不够的。
在管道中腐蚀产物可能会导致进一步的问题；增加表面粗糙度和减少直径可以导致压力降的增加，同时也会引起接收终端设备的一些问题，比如腐蚀和堵塞［3］。
管道系统可能由主运输干线连接一些输送支线组成，这样一个复杂的海底管道系统的完整性管理不是很简单的。
铸铁管微生物腐蚀原理英语
铸铁管微生物腐蚀原理英语Corrosion of Microorganisms in Cast Iron PipesThe corrosion of cast iron pipes by microorganisms is primarily driven by biological processes. These microorganisms, such as bacteria, fungi, and algae, colonize the surface of the pipe and form a thin biofilm. This biofilm acts as a protective layer for the microorganisms, shielding them from the harsh environment and providing essential nutrients for their growth and proliferation.One of the key mechanisms by which microorganisms cause corrosion in cast iron pipes is through the production of corrosive metabolites. Bacteria, for example, can produce organic and inorganic acids as byproducts of their metabolic processes. These acids can lower the pH of the surrounding environment, creating an acidic condition that is highly corrosive to cast iron.In addition to acid production, microorganisms can also facilitate corrosion by promoting depolarization in electrochemical reactions. They can act as catalysts in the formation of corrosion cells, which are electrochemical systems that allow the transfer of electrons between the cathodic and anodic areas on the pipe's surface. This transfer of electrons can result in the corrosion of the cast iron material.Another important preventive measure is the use of corrosion-resistant coatings or linings on the interior surface of the cast iron pipes. These coatings act as a barrier between the pipe material and the corrosive environment, reducing the contact between microorganisms and the pipe's surface.Regular inspection and maintenance of cast iron pipes are also crucial in preventing the corrosion caused by microorganisms. This can include the removal of accumulated biofilms and debris, as well as the repair or replacement of damaged sections of the pipe.。
关于CO_2对常用管道金属腐蚀的研究
应用广场版Ａｐｐｌｉｃａｔｉｏｎ１导言二氧化碳（ＣＯ２）溶于水后对部分金属材料有极强的腐蚀性，由此而引起的材料破坏统称为ＣＯ２腐蚀。
ＣＯ２在水介质中能引起钢铁迅速的全面腐蚀和严重的局部腐蚀。
ＣＯ２腐蚀典型的特征是呈现局部的点蚀、癣状腐蚀和台面状腐蚀，造成了严重的经济损失和社会后果。
随着油气井含水量的增加、深层含ＣＯ２油气层的开发日益增多，注ＣＯ２强化采油工艺的推广，我国埋地管道８０％以上是１９７８年以前建成的，目前已进入老龄期，漏油事故就日益增多。
ＣＯ２腐蚀问题越来越突出，已成油田及油管生产设计部门一个急待解决的重要课题。
２正文２．１ＣＯ２的腐蚀机理关于二氧化碳腐蚀机理方面的研究工作较多。
据文献资料①介绍，二氧化碳腐蚀遵循以下机制，阳极反应如下：Ｆｅ＋Ｈ２ｏ→ＦｅＯＨａｄ＋Ｈ＋＋ｅ；ＦｅＯＨａｄ→ＦｅＯＨ＋＋ｅ；ＦｅＯＨ＋＋Ｈ＋→Ｆｅ２＋＋Ｈ２Ｏ阴极反应有以下两种情况：１）非催化的氢离子阴极还原反应：ＣＯ２ｓｏｌ＋Ｈ２Ｏ→Ｈ２ＣＯ３ｓｏｌ；Ｈ２ＣＯ３ｓｏｌ→Ｈ＋＋ＨＣＯ－３；Ｈ－ｓｏｌ→Ｈ＋ａｄ；Ｈ＋ａｄ＋ｅ→ＨａｄＨａｄ＋Ｈ＋ａｄ＋ｅ→Ｈ２ａｄ；２Ｈａｄ→Ｈ２ａｄ；Ｈ２ａｄ→２Ｈ２ｓｏｌ；Ｈａｄ→Ｈａｂ２）表面吸附ＣＯ２ａｄ。
的氢离子催化还原反应：ＣＯ２ｓｏｌ→ＣＯ２ａｄ；ＣＯ２ａｄ＋Ｈ２Ｏ→Ｈ２ＣＯ３ａｄ；Ｈ２ＣＯ３ａｄ＋ｅ→Ｈａｄ＋ＨＣＯ－３ａｄ；Ｈ２ＣＯ３ａｄ→Ｈ＋ａｄ＋ＨＣＯ－３ａｄＨ＋ａｄ＋ｅ→Ｈａｄ；ＨＣＯ－３ａｄ＋Ｈ＋ｓｏｌ→Ｈ２ＣＯ３ａｄ；Ｈａｄ＋Ｈ＋ａｄ＋ｅ→２Ｈａｄ；２Ｈａｄ→Ｈ２ａｄ２Ｈ２ａｄ→Ｈ２ａｄ；Ｈａｄ→Ｈａｂ式中ａｄ，ｓｏｌ，ａｂ分别为吸附，溶液和吸收：Ｈａｄ表示吸附在钢铁表面的氢原子，Ｈａｂ表示渗入钢铁内即钢铁所吸收的氢原子，Ｈ＋ｓｏｌ表示溶液介质体系中的Ｈ＋。
其中，吸附在钢铁表面的氢原子既可能结合成Ｈ２脱附，也可能被金属吸收，从而导致产生氢脆。
二氧化碳分子也可以直接被吸附在钢铁表面，从而对钢铁表面产生作用。
分析检验管路维修英语作文
In the realm of industrial maintenance, the inspection and repair of pipeline systems are critical tasks that ensure the smooth operation of various facilities. The process involves meticulous examination and, when necessary, the rectification of any defects or damages that may compromise the integrity and efficiency of the system. This essay delves into the intricacies of pipeline inspection and repair, drawing from personal experiences and industry practices.The journey into the world of pipeline maintenance began with a comprehensive understanding of the systems layout and the materials it handles. Whether its a water supply system, a gas pipeline, or a network of oil conduits, each has its unique set of challenges and requirements. The first step in the inspection process is a visual examination, where the exterior of the pipeline is scrutinized for signs of wear, corrosion, or damage. This is often followed by a more indepth analysis using advanced technologies such as ultrasonic testing, which can detect internal flaws without the need for invasive procedures.One vivid memory from the field was when a gas pipeline in a suburban area was suspected to have a leak. The urgency of the situation was palpable as the potential for a catastrophic event loomed. Using a combination of gas detectors and infrared imaging, the team was able to pinpoint the source of the leak. The precision of these tools was nothing short of remarkable, and it underscored the importance of staying abreast of technological advancements in the field.Once a defect is identified, the repair process begins. Depending on thenature and severity of the issue, this can range from simple patching to complete pipeline replacement. In one instance, a section of a water main had corroded to the point where it was no longer safe to carry water under pressure. The decision was made to replace the affected segment. The process involved careful excavation to expose the damaged area, precise cutting of the pipeline, and the installation of a new, robust section. The team worked meticulously, ensuring that the new joint was not only secure but also compatible with the existing system to prevent future issues.Safety is paramount in all aspects of pipeline maintenance. Protective gear, such as helmets, gloves, and safety glasses, are standard issue. Moreover, the use of personal protective equipment is complemented by strict adherence to safety protocols, which include regular communication among team members, the use of warning signs, and the implementation of traffic control measures when necessary.The environmental impact of pipeline repairs is another consideration that cannot be overlooked. The disposal of removed materials must be done in an ecofriendly manner, and efforts are made to minimize the disruption to the surrounding ecosystem. In one project, the team was careful to backfill the excavated area with the same type of soil, ensuring that the natural habitat was restored to its original state as closely as possible.The role of communication in pipeline maintenance is equally significant. Regular updates are provided to stakeholders, including the facility management and the local community, to keep them informed about the progress of the work and any potential impacts. This open line ofcommunication helps to build trust and ensures that any concerns are addressed promptly.In conclusion, the inspection and repair of pipeline systems is a complex and multifaceted task that requires a combination of technical expertise, safety awareness, and environmental responsibility. Personal experiences have highlighted the importance of using stateoftheart tools for accurate detection of issues, the meticulous approach to repairs, and the continuous communication with all parties involved. As the industry evolves, so too must the practices and technologies used to maintain the integrity and efficiency of these vital systems.。
天然气管道腐蚀与防腐分析
（ １ ． 辽 宁石 油化 工大 学，辽 宁 抚顺 １ １ ３ ０ ０ １ ； ２ ．中国石 油大 学（ 北 京） ，北 京 １ ０ ２ ２ ４ ９）
摘
要：腐蚀对 管道系统 的可靠性和使用 寿命起 到关键 作用 ，油气集输管线的失效形式主要表现 为腐蚀失
２ ０ １ ３ 年 ５月
第４ ２ 卷第 ５ 期
Ｃ ｏ ｎ ｔ ｅ ｍ ｐ ｏ ｒ ａ ｙ
当
代
化
工
Ｖ ｏ １ ． ４ ２． Ｎ ｏ ． ５ Ｍ ａ ｙ， ２ ０ １ ３
天然气管道腐蚀 与防腐分析
ｐ ｉ ｐ ｅ ｌ ｉ ｎ ｅ ｓ ｉ Ｓ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｆ ａ ｉ ｌ ｕ ｒ ｅ ． Ｔｈ ｅ ｎ ｕ ｍｂ ｅ ｒ ｏ ｆ ａ ｃ ｃ ｉ ｄ ｅ ｎ ｔ ｓ ｃ ａ ｕ ｓ ｅ ｄ ｂ ｙ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｉ ｓ ｔ ｏ ｏ ｎ ｕ ｍｅ ｒ ｏ ｕ ｓ ｔ ｏ ｅ ｎ ｕ ｍｅ ｒ ａ ｔ ｅ ｅ ｖ ｅ ｒ ｙ ｙ ｅ ａ ｒ ， ｗｈ ｉ ｃ ｈ ｃ ａ ｕ ｓ ｅ ｓ ｓ ｅ ｒ ｉ ｏ ｕ ｓ ｅ ｃ ｏ ｎ ｏ ｍｉ ｃ １ ｏ ｓ ｓ ｅ ｓ ａ ｎ ｄ ｃ ａ ｓ ｕ ａ ｌ ｔ ｉ ｅ ｓ ． Ｉ ｎ ｔ ｈ ｉ ｓ Ｐ ａ Ｄ ｅ ｒ ， ｒ ｅ ａ ｓ ｏ ｎ ｓ ｔ ｏ ｃ ａ ｕ ｓ ｅ ｃ ｏ ｒｏ ｓ ｉ ｏ ｎ ｏ ｆ ｎ ａ ｔ ｕ ｒ ａ １ ｇ ａ ｓ ｐ ｉ ｐ ｅ ｌ ｉ ｎ ｅ ｓ ｗｅ ｒ ｅ ａ ｎ ａ ｌ ｙ ｒ ｚ ｅ ｄ ｆ ｒ ｏ ｍ ｔ ｗｏ ａ ｓ ｐ ｅ ｃ ｔ ｓ ｏ ｆ ｉ ｎ ｓ ｉ ｄ ｅ ａ ｎ ｄ ｏ ｕ ｔ ｓ ｉ ｄ ｅ Ｗａ ｌ １ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ． ａ ｎ ｄ ａ ｎ ｔ ｉ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｍｅ ａ ｓ ｕ ｒ ｅ ｓ ｗｅ ｒ ｅ ｐ ｕ ｔ ｆ ｏ ｒ ｗａ ｒ ｄ ， ｗｈ ｉ ｃ ｈ ｃ ａ ｒ ｌ ｐ ｒ ｏ ｖ ｉ ｄ ｅ ｎ ｅ ｃ ｅ ｓ ｓ ａ ｒ ｙ ｒ ｅ ｆ ｅ ｒ ｅ ｎ ｃ ｅ ｓ ｎｄ ａ ｔ ｈ ｅ ｏ ｒ ｅ ｔ ｉ ｃ ａ ｌ ｂ ａ ｓ ｉ ｓ ｆ ｏ ｒ ａ ｃ ｔ ｕ ａ ｌ ａ ｎ ｔ ｉ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｗｏ ｒ ｋ ｏ ｆ ｎ ａ ｔ ｕ ｒ ａ ｌ ｇ ａ ｓ ｐ ｉ ｐ ｅ ｌ ｉ ｎ ｅ ｓ ． Ｋｅ ｙ ｗｏ ｒ ｄ ｓ ： Ｎａ ｕｒ ｔ ａ ｌ ｇ ａ ｓ ； Ｐ ｉ ｐ ｅ ｌ ｉ ｎ ｅ ｃ ｏ ｒｏ ｓ ｉ ｏ ｎ ； Ｄａ ｍａ ｇ ｅ ； Ｐ ｒ ｅ ｖ ｅ ｎ ｔ ｉ ｏ ｎ ｍｅ ａ ｓ ｒｅ ｕ ｓ
腐蚀管道有限元分析
AbstractWith the development of industrial level, oil and gas demand is rising year by year. Now, there are hundred thousand meters of pipeline in our country, most of these pipes was built in the last century 70s,which has more than 30 years of design life. Production is one of the main causes of accident because the tube from corrosion. These corrosion include: pipeline anticorrosive coating aging, deformation, cracks, stripping, into the outer wall of pipeline corrosion medium in soil environment, and caused by pipeline medium corrosion lining pipe body corrosion. The formation of corrosion defects on the one hand to reduce the pressure capacity of pipe itself, on the other hand also can weaken the pipe fatigue resistance。
The problem is not allow to ignore. According to certain evaluation method, evaluate the corrosion of pipeline pressure ability, is in order to determine the maximum permissible operating pressure and maximum allowable defect size. So as to make the right decision, step-down, repair, replacement etc. Different methods are due to the diversity analysis method and rapid development of pipeline materials. Therefore, analyze the evaluation method of comparison, points out its advantages, limitations and scope, best help get reasonable evaluation result. Foreign researchers for the limit bearing capacity of research, mainly through numerical simulation and prototype pipe blasting experiment with the combination of means, on the basis of a series of specifications and methods are put forward since the early 1980s. To sum up the corrosion of pipeline pressure capacity for the pipeline construction and safe operation is of great significance.In this paper, the ultimate bearing capacity of the pipeline with corrosion defects is carried out by the finite element analysis of ABAQUS software.(1)The finite element model is established for pipeline with pitting corrosion, longshaped defects and spiral defect by hexahedral element and tetrahedral element.(2)The Mises V on stress criterion is proposed to determine the failure of the pipeline.The results are verified of data for 16 prototype pipe blasting experiments.(3)On this basis, the current application of NG-18 AGA, B31G ASME and DNVmethods are analyzed and evaluated, and pointed out the determination of defects in the internal pressure.(4)A formula for predicting the internal pressure of pipeline failure is improved.(5)By the example of Qin Jing and Qin Qin pipeline the influence of the defect size andload on the pressure bearing capacity of the pipeline is analyzed.(6)A method for determining the influence distance of pit defects of pipeline defects isproposed by using the contour map.(7)The results of finite element analysis of spiral pipe defects show that MOK can beused to evaluate the pressure bearing capacity of the failure internal pressure of the spiral pipe.Key words：pipeline; corrosion; bearing capacity; finite element1.2国内外的研究状况国外研究人员先后从20世纪80年代初期开始管道极限承压能力的研究，主要是通过数值模拟与原型管道爆破实验相结合的手段，在此基础上提出了一系列的规范和方法。
管道的应力腐蚀断裂
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管道的应力腐蚀断裂
四川省的天然气管线由于介质未处理好，在被输送的天然气中H2S大大超过规定的含量，曾发生多次爆破事故。
据国外文献介绍，美国1955年第一次发生由于氢脆而产生的氢应力破坏，六十年代出现了其他形式的应力腐蚀断裂，以后随着时间的延续，这类破坏事故越来越多，而应力腐蚀断裂也越来越多地为管道工作者所关注，并成为研究的课题。
应力腐蚀断裂简称为SCC，这系由英文名词Stress Corrosion CracKing而来的，其定义为：在应力和介质联合作用下，裂纹的形成和扩展的过程叫做应力腐蚀，由于应力腐蚀而产生的断裂称为应力腐蚀断裂。
当原始缺陷的长度2a小时临界裂纹长度2ac时，管线是不会断裂的，但由于疲劳或(和)环境的作用，裂纹长度可以增长，当原始缺陷长度逐渐增长，最后达到2ac时，则管道产生断裂。
这里只将讨论后者，即在环境和应力相互作用下引起的应力腐蚀断裂。
一、应力腐蚀的机理
为说明应力腐蚀需先简单的介绍腐蚀反应。
大家知道，钢铁放在潮湿的空气中，就会生锈，锈不断脱落，就会导致截面减小和重量减轻，这称为钢铁受到了腐蚀。
腐蚀是一种电化学过程，它又可分为阳极过程和阴极过程，这二者是共存的。
金属原子是由带正电的金属离子，对钢来说，就是二价的铁离子F2+和周围带负电的电子云(用e-来表示）构成的，如下所示：
Fe→Fe2++2e-上式是一个可逆反应。
当铁遇到水，铁离子Fe2+ 和水化合的倾向比Fe2+与e-结合成金属的倾向还要强，因此金属铁遇到水后就会发生如下反应：
.。
管道两相流冲刷腐蚀的CFD研究进展
Ｒｅ ｓ ｅ ａ ｒ ｃ ｈ Ｐｒ ｏ ｇ ｒ ｅ ｓ ｓ ｉ ｎ ＣＦＤ ｏ ｆ Ｐｉ ｐｅ ｌ ｉ ｎｅ Ｅｒ ｏ ｓ ｉ ｏ ｎ－ Ｃｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｉ ｎ Ｔｗ ｏ Ｐｈａ ｓ ｅ Ｆｌ ｏ ｗ
ＺＨＡＯ Ｚｈｕ ａ ｎ ｇ， Ｙ ｕ － ｇｕ ｏ， Ｔ Ｉ ＡＮ Ｌｅ ｉ ， ＷＵ Ｄｏ ｎ ｇ
（ Ｃｏ ｌ ｌ ｅ ｇ ｅ ｏ ｆＰ ｅ ｔ ｒ ｏ ｌ ｅ ｕ ｍ Ｅ ｎ ｇ ｉ ｎ ｅ ｅ ｒ ｉ ｎ ｇ ， Ｌｉ ａ ｏ ｎ ｉ ｎ ｇ Ｓ ｈ ｉ ｈ ｕ ａ Ｕｎ ｉ ｖ ｅ ｒ ｓ ｉ ｔ ｙ ， Ｌ ｉ ａ ｏ ｎ ｉ ｎ ｇ Ｆ ｕ ｓ ｈ ｕ ｎ １ １ ３ ０ ０１ ， Ｃｈ ｉ ｎ ａ ）
赵 状 ，吴 玉 国 ， 田 曼 ，吴 栋
（ 辽宁 石油 化工 大学 石油 天然气 工 程学 院 ， 辽宁 抚 顺 １ １ ３ ０ ０ １）
摘
要 ： 介绍 了冲刷腐蚀对石化行业 的危 害 ，阐述了影响 冲刷腐蚀 的因素 ，即主要是流体力学 因素 、材
料 因素 、固相颗粒等 因素 的耦合作用 。对计算流体力学 （ Ｃ Ｆ Ｄ）方法在管道 防腐 中研究 的进展情况进 行总结 ， 指 出了研究 的优点和缺点 。Ｃ Ｆ Ｄ数值模拟为防腐蚀研究提供 了新 的方法 。通过模拟结果 可以预测腐蚀 的发生和 发展 ，并 为管道优化设计和工艺 防腐提供可靠 的理论依 据。 关 键 词 ：冲刷腐蚀 ；研究进展 ；Ｃ Ｆ Ｄ；腐蚀预测
ｉ ｔ ｓ ａ ｄ ｖ ａ ｎ ｔ ａ ｇ ｅ ｓ ａ ｎ ｄ ｄ ｉ ｓ ａ ｄ ｖ ａ ｎ ｔ ａ ｇ ｅ ｓ ｗｅ ｒ ｅ ｐ ｏ ｉ ｎ ｔ ｅ ｄ ｏ ｕ ｔ ． ＣＦＤ ｎ ｕ ｍｅ ｒ ｉ ｃ ａ ｌ ｓ ｉ ｍｕ ｌ ａ ｔ ｉ ｏ ｎ ｐ ｒ ｏ ｖ ｉ ｄ ｅ ｓ ａ ｎ ｅ ｗ ｍｅ ｔ ｈ ｏ ｄ ｏｒ ｆ ｓ ｔ ｕ ｄ ｙ ｏ ｎ ｔ ｈ ｅ ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｐ ｒ ｏ ｔ ｅ ｃ ｔ ｉ ｏ ｎ ． Ｔｈ ｅ ｓ ｉ ｍｕ ｌ ａ ｔ ｉ ｏ ｎ ｃ ａ ｎ ｐ ｒ ｅ ｄ ｉ ｃ ｔ ｔ ｈ ｅ ｅ ｒ ｏ ｓ ｉ ｏ ｎ — ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｏ ｃ ｃ ｕ ｒ ｒ ｉ ｎ ｇ ａ ｎ ｄ ｄ ｅ ｖ ｅ ｌ ｏ ｐ ｍｅ ｎ ｔ ， ｗｈ ｉ ｃ ｈ ｃ ａ ｎ ｐ ｒ ｏ ｖ ｉ ｄ ｅ ｒ ｅ ｌ ｉ ａ ｂ ｌ ｅ ｔ ｈ ｅ ｏ ｒ ｅ ｔ ｉ ｃ ａ ｌ ｂ ａ ｓ ｉ ｓ ｏｒ ｆ ｐ ｉ ｐ ｅ ｌ ｉ ｎ ｅ ｏ ｐ ｔ ｉ ｍｉ ｚ ａ ｔ ｉ ｏ ｎ ｄ ｅ ｓ ｉ ｇ ｎ ａ ｎ ｄ ｃ ｏ ｒｏ ｓ ｉ ｏ ｎ ｐ ｒ ｏ ｔ ｅ ｃ ｔ ｉ ｏ ｎ ． Ｋｅ ｙ ｗｏ ｒ ｄ ｓ ： Ｅｒ ｏ ｓ ｉ ｏ ｎ — ｃ ｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ； Ｒｅ ｓ ｅ ａ ｒ ｃ ｈ ｐ ｒ ｏ ｇ ｒ ｅ ｓ ｓ ； ＣＦ Ｄ； Ｃｏ ｒ ｒ ｏ ｓ ｉ ｏ ｎ ｐ ｒ ｅ ｄ ｉ ｃ ｔ ｉ ｏ ｎ
管道防腐涂料文献索引
管道防腐涂料文献索引NACE 2011-2007年会技术报告目录编译王向农注解：文献编号为NACE年会技术报告的原始编号，前两位数字代表年份。
如“11269”表示2011年会技术报告，“08228”代表2008年会技术报告，以此类推。
11020 Electrochemical Properties During Film Degradation of Coated Steel防腐涂层钢材涂膜退化过程的电化学特性作者：Noboru Kawai, Junichi Tani, Masanori Nagai and Hiroyuki Tanabe页数：11页Organic coatings are widely used in the steel structures of power transmission and distribution systems to protect against corrosion. Early and accurate detection of coating degradation is clearly of critical importance. We investigated two methods for evaluating coating degradation—the alternating current (AC) impedance method and the current-interrupt (CI) method—by exposing coated steel specimens to either long-term atmospheric exposure or shorter-term salt-water immersion, and then measuring their electrochemical behavior. We also analyzed coating degradation by x-ray probe microanalysis.11022 The Study of Diffusion Ions and Water in Powder and Liquid Epoxy Coatings of Pipeline with Using Fluorescence Microscopy and AFM Methodology 用荧光显微镜和原子力显微镜（AFM）方法研究粉末与液体环氧涂料中离子和水的扩散作者：Hamidreza Esfahany页数：11页FBE coatings are known to absorb moisture and pass current. They allow current to pass and exhibit a reduced electrical resistance under cathodic protection. The results of cathodic disbonding and EIS tests for FBE coatings show that with increasing of permittivity factor of coating, the radius of cathodic disbandment increases. When epoxy exposes in electrolyte, the diffusion of ions and water in coating caused of reduction of electrical resistance. The cathodic disbonding radius (r) decreases with diminish passing ions and water from epoxy coating. The precise mode by which water and ions enter organic coatings when subjected to corrosive environments remains unresolved. Local electrochemical methods have provided insight into the local nature of the under film degradation process. But these local electrochemical methods have not provided conclusive evidence as to whether the transport of waterand ions occur through discrete or regional heterogeneities within the organic film. The mode of water diffusion and interaction with liquid and powder epoxy coatings that used for internal and external coating of pipe line with fluorescence microscopy and AFM methodology was investigated. It seems that the flux of water and ions across the film by the presence of small imperfections or pores which extend through the thickness of coating and have cross-sections that are larger than free areas typically present between the molecular chains of matrix for the ions passing through the bulk matrix of the polymer film. Furthermore, there are regional differences within a single coating with regards to ion selectivity.10001 Studies on the Bond Durability Between the Steel and 3 Layers PE/PP Coatings in Hot/Wet Environment高温潮湿环境中钢与三层聚乙烯/聚丙烯粘合持久性的研究作者：Denis Melot页数：15页For the last few years, an oil company has carried out laboratory testing of tri-layers PE and PP pipe coatings in hot wet environment. The objective was to simulate the disbondment from the steel substrate noted in some cases in the field (with no corrosion associated), and understand the physico-chemical mechanism at the origin of the loss of adhesion experienced. This paper will sum up the results obtained so far from this RD effort, with a special highlight on the following points : Durability of the bond between the steel and the FBE primer/Influence of water diffusion；Influence of the FBE type and ageing temperature on the disbondment；Influence of internal stresses on the disbondment of three layers coatings.10002 Failure Analysis of Three Layer Polypropylene Pipeline Coatings三层聚丙烯管道防腐层的失效作者：Ali Noor Moosavi, Benjamin T. A. Chang and Kamal Mohamed Morsi页数：11页Three layer polypropylene (3LPP) pipeline coatings failed prematurely in the oilfields of Abu Dhabi in the United Arab Emirates (UAE). A failure investigation and analysis into this phenomenon was instigated. Two major failure modes were found: (i) PP cracking at field joint coating (FJC) and mainline pipe coatings, and (ii) 3LPP coating disbondment from fusion bonded epoxy (FBE) -steel interface. The PP cracking is attributed to thermo-oxidative degradation and high residual stresses in PP. The coating disbondment has been found to be due to high residual stress concentration and adhesion loss after moisture interaction or thermo-oxidative degradation of the FBE primer. The failure analysis results will assist us in our future external pipeline coating selection. The new high temperature external gas pipeline coatings can be either single layer FBE, multi-layer FBE, or 3LPP. But any candidate coating system must demonstrate its thermal stability and adhesion durability in UAE Sabkha environment. We hope that FBE and PP manufacturers will do more research toimprove PP and FBE formulations to mitigate PP cracking, to improve FBE thermal stability and adhesion durability in the high temperature Sabkha wet and dry sandy soil environment.10003 Study of a Failure a Decohesion Failure in a Three Layer Coating of a 24" Gas Pipeline in Veracruz in South East Mexico墨西哥东南Veracruz的24英寸天然气管道三层防腐层脱粘失效的研究作者：Lagos, Magana, Lopez, Padilla, Canto, Villamizar, Escalera, Ascencio, and Martinez页数：10页The three layer pipeline coating system is one of the fastest growing and more accepted systems in the world, in great part due to the combination of the excellent adhesion properties of the FBE, and the excellent water impermeability and mechanical resistance of the HDPE. We report a case study of a disbondment failure occurred at a 24” gas pipeline and the steps taken to try to determine the root cause of the failure.10004 Internal Coating of Multiphase Pipelines - Requirements for the Coating 多相流管道内涂层–涂层的要求作者：Ole Oystein Knudsen, Astrid Bjorgum and Ann Karin Kvernbraten页数：12页Pressure drop along the pipeline is the main obstacle to transportation of unprocessed or partly processed multiphase fluids over long distances. Several parameters contribute to pressure drop in multiphase flow, e.g. liquid hold-up, precipitations, gas-liquid surface drag forces, liquid wetting of pipe wall and surface roughness. Application of coatings inside the pipeline can reduce pressure drop by preventing corrosion, preventing precipitations on the pipe wall and modify the pipe wall wetting properties. Meso scale pressure drop tests have shown that pressure drop is significantly affected by moderate corrosion, even in multiphase flow, demonstrating that application of internal coatings is beneficial. However, the coating must have the same lifetime as the pipeline. In this work we have tried to identify the most important coating degradation mechanisms and to find relevant test methods for evaluation and qualification of coatings.10006 On Development of Accelerated Testing Methods for Evaluating Performance of Organic Coatings Above 100° C开发用于评价高于100℃温度下有机涂层性能的加速试验方法作者：Pavan K. Shukla, Roberto Pabalan, Lietai Yang and Mark A. Smith页数：15页Organic coatings are applied to protect underground and aboveground pipelines and other objects from corrosion. Hot-water soak and cathodic disbondment tests are routinely used in the coating industry to evaluate the performance of organic coatings that protect metal pipes in offshore (seawater) and onshore (aboveground or underground) applications. Numerous technical standards, which specify the operating conditions and test parameters, are available. The technical standards are applicable when the operating temperature is below 100 °C. However, the organic coatings could be subjected to temperatures above 100 °C when a pipeline is carrying hot fluids. Several attempts have been made to improve the existing test methods for evaluating coating performance above 100 °C. In this paper, we provide a critical review of published literature on coating performance evaluation above 100 °C. In addition, we discuss the test conditions that must be considered in developing accelerated coating evaluation methods above 100 °C.10007 Test Method for Studying Cathodic Disbonding at High Temperature研究高温下阴极剥离的试验方法作者：Ole Oystein Knudsen, Tor Gunnar Eggen and Kristian Karlsen Brende页数：11页Cathodic disbonding at elevated temperatures has not been thoroughly studied. As offshore oil and gas production moves towards higher temperatures there is a need for a better understanding of coating degradation, products with higher temperature limits and probably also new guidelines for design of cathodic protection. Standard test methods for high temperature cathodic disbonding are available, primarily for pipeline coatings. However, these methods may not be applicable for offshore structural coatings. The objective with this work is to design a test method that simulates the exposure conditions for coatings on submerged high temperature constructions. Cathodic disbonding is normally considered to be the main degradation mechanism for submerged coatings, but as temperature increases other degradation mechanisms may actually become more important, e.g. thermal degradation of the binder. Hence, how the high temperature affects e.g. film and barrier properties will also an important part of this work.10008 High Temperature Cathodic Disbondment Tests高温阴极剥离试验作者：Amal Al-Borno, Ph.D., Mick Brown, Ph.D., and Sherry Rao, M.Sc.页数：24页Current test standards for Cathodic Disbondment (CD) tests do not include tests that are close to or above 100°C; primarily because of difficulties associated with evaporation of the electrolyte in such tests and because there has been little demand for such high temperatures. However, with the increasing use of pipelines and other vessels at temperatures above 100°C, the need for preferably standardized tests that will evaluate coatings at these higher temperatures has become something that needsurgent attention. Many currently used CD test standards employ methods that have both pipe sample and testing electrolyte at the same temperature but these tests have not been viable for test temperatures above 80°C - 90°C because of electrolyte evaporation. This paper describes the development and testing of a high temperature test apparatus that allows for CD testing in a pressurized test vessel. The vessel allows testing at high temperatures of electrolyte as well as standard potential measurements and control. It also provides methods for controlling oxygen concentration in the electrolyte. Comparative data from tests using the new apparatus and other test methods are included that demonstrate the influence of changes in temperature, pressure, and oxygen content in the test electrolyte. Further to this work, another CD test cell was designed, built and tested which incorporates a cooling jacket on the cell such that high temperature CD tests can be run at ambient pressure conditions. This paper includes discussion of the affects of oxygen concentration levels, electrolyte temperatures, and the merits of the different CD test methods.10009 A New Approach for Determination of Wet Adhesive Strength of Epoxy Coatings on Steel Substrate测定环氧涂层在钢底材上湿粘附强度的新方法作者：H. Jiang, R. Browning, B.T.A. Chang and H.J. Sue页数：8页A standardized scratch test methodology (ASTM D7027-05 and ISO 19252) was employed to determine the adhesive strength of fusion-bonded epoxy (FBE) coating on steel. Finite element method (FEM) modeling was carried out to simulate the scratch process. Correlation between the experimental findings and FEM modeling allows for quantitative assessment of the adhesive strength of FBE coating on steel substrate. The proposed test method for evaluation of adhesive strength of FBE coatings on steel substrate appears promising.10010 A New 3LPP Offshore Field Joint Coating一种新型近海3LPP防腐管道现场补口技术作者：Meghan Mallozzi and Mario Perez页数：9页The coated field joint area is often viewed as the weak link in corrosion mitigation. A poor quality coating system applied to the field-joint area only adds to this weakness. Field-joint coatings require special attention because of application limitations, compatibility of mainline coating, timing constraints, and variable environmental conditions. A new Protective Network Coating (PNC) is being investigated that may provide an enhanced coating system for offshore field joints helping to better protect pipe assets in global offshore projects. The PNC technology has the ability to adhere to fusion bonded epoxy coatings without the need for a polyolefin adhesive. PNC is also compatible with polypropylene leading to a seamless system between the mainline coating and field joint coating. This paper reviews the development of a new3LPP field joint coating system.10012 New Developments of Mid-TG-FBE Powder Coatings to Meet the Requirements of Pipe Coaters and Pipeline Owners为满足管子防腐厂和管道业主需要而新开发的中等玻璃化温度熔结环氧粉末涂料作者：Dr V. Boerschel页数：21页The development of oil and gas fields at increasing depths in recent years, both onshore and offshore, and the need for pipelines to carry viscous media such as oil sands at high temperature to improve flow efficiency, has created a requirement for the coatings used to protect such pipelines from corrosion to be able to operate in a temperature range 120-150oC. One of the most successful coating types for the corrosion protection of steel pipes is Fusion Bonded Epoxy (FBE) powder coatings but, until now, the range of options available for pipelines operating at high temperatures has been mainly limited to either a standard FBE applied at a higher film thickness or as a dual-layer system, or an FBE with a high glass transition (Tg) of the film, applied as a primer for a 3-layer polypropylene system. Whilst it is widely accepted that it is preferable for the Tg of the coating film to be at least 10oC above the operating temperature of the pipeline there are few FBE coatings commercially available with a film Tg in the range 130-160oC to allow them to be used at the higher operating temperatures now required. The few that do exist have relatively limited flexibility particularly at low temperatures which limits the range of environmental conditions that pipelines coated with such products can withstand. This paper presents the development of a range of Mid-Tg-FBE powder coatings with film Tg’s in the range 130-150oC and test methods with conclusions. These coatings demonstrate excellent adhesion and mechanical performance, even at temperatures down to -60oC, thus greatly expanding the range of field conditions and pipeline operating temperatures that can be accommodated. The excellent flexibility of these coatings enable them to be applied as a single-layer FBE coating, and as a dual-layer FBE coating system, as well as a primer for 3-layer polypropylene systems. The growing commercial track record of these products is confirming the excellent results seen in production and laboratory testing.10015 High Performance and Environmentally Friendly Coating System for Water Ballast Tank of Ship in the Shipbuilding Industries用于造船工业船舶压载舱的高性能环境友好型涂层系统作者：Sangki Chi, Junho Ha, Seunghyun Kim, Byeongwan Kim, Minyoung Shon页数：18页Organic coatings are widely used in ship structure for corrosion protection and IMO PSPC Guideline has recently been issued to achieve high anti-corrosion properties.Currently, solvent borne epoxy paints are generally used in ship coating, especially water ballast tank (WBT) and the emission of volatile organic compound (VOC) materials such as hydrocarbon solvents is inevitable. Evaporation of solvent was known as pollutant material and resulting in hazard to health of spray worker. Therefore, the current trend is toward the application of lower VOC coating material, especially solvent free coating containing solvent less than 5% or water borne paint for environmental and human protection. Additionally, multi-coating system of ship coating including 2- main coating and 2-strip coating was also raised as one of reason for air pollution. In present study, the performances of commercially used solvent free epoxy paint with 1-main coating and 1-stripe coating has been evaluated comparing with those of commercially used solvent-borne paint with 2-main coating and 2-strip coating in terms of anti-corrosion, build-up properties, crack resistance and contents of volatile organic compound. From the results, it would be clearly indicated that solvent free epoxy coating showed equivalent or higher anti corrosion and build up performances than solvent borne epoxy.10016 Feasibility Study of Rapid Cure Coatings for Marine Environment用于海洋环境的快速固化涂料的可行性研究作者：Seong-Mo Son, Mong Kyu Chung, Chil Seok Shin and Ki Hong页数：17页A feasibility study on the application of several kinds of rapid cure coating system to water ballast tank was conducted in terms of curing characteristics and coating performance. The coating systems employed in this study were three types of solvent free rapid cure epoxy coatings, an isocyanate curable polyurethane coating and a polyurea coating system. Polyurethane and polyurea coating were especially formulated for sea water ballast tank service. Based on the study of curing characteristics and coating performance of the polyurethane and polyurea coating system, it was found that lower adhesion strength of the coatings over power tool treated surface and lower surface profile was the result suggesting that additional primer application is needed in order to obtain required adhesion strength. Moreover corrosion resistance of the fast cure coatings especially in water immersion was inferior to that of the required epoxy coatings.10017 Soluble Salt Criteria of Epoxy Coatings for Ship's Water Ballast Tank用于船舶压载舱的环氧涂料的可溶性盐分标准作者：Chul-Hwan Lee, Sung-Mo Son, Yun-Ho Baek, and Dae-Young Kim页数：14页Soluble salt contamination of the substrate prior to coating application will cause premature coating failure at the coating/steel interface as well as underfilm corrosion of the steel substrate, especially when the surface concentration of the soluble salts exceeds a critical level. So, in order to prevent this salt-induced premature coating failure IMO’s PSPC regulation adopted recently for ship’s water ballast tank specifiedthe allowable NaCl limit to be 50 mg/m2 or less for primary and secondary surface preparation. The finalized criterion on the salt contamination, however, can be still subjected to argument mainly due to lack of reasonable technical justification for coating systems of ship’s water ballast tank. In this study, coating performance of epoxy coatings for ship’s water ballast tank were evaluated with soluble salt levels, especially NaCl, in terms of adhesion strength and blistering resistance test in immersion, condensation, and cathodic protection environment to propose reasonable soluble salt criterion. The results based on the coating performance tests for 6 months suggested the maximum allowable NaCl of 70 to 100 mg/m2, depending on epoxy coating formulation used. It is recommended that blistering resistance should be evaluated to determine the criterion of soluble salt since the maximum allowable salt level does vary with coating formulation.10021 Evaluation of Anticorrosive Coatings for Tanker Walls to Transport Oil in a High Salinity Environment, in the Presence of Tension, Temperature and CO2 受到张力、温度和二氧化碳影响的高矿化度环境中运输原油的油轮内壁防腐涂层的评价作者：Neusvaldo Almeida, Adriano Garcia Bernal, Victor Solymossy and Flavio Augusto S. Serra页数：15页The offshore heavy oil project uses Floating Production, Storage and Offloading (FPSO) structural tanks to act as oil separators (washing tanks) a vital requirement. These tanks operate with a continuous layer of produced water at high operational temperatures and high residence time, creating a critical corrosive environment. This condition is far beyond typical conditions for tankers and makes the development of a special test necessary to qualify paint systems for that condition. Traditionally the qualification of paint systems in Brazil offshore units is based on NACE TM-0104 and ISO 20340 standards. But these standards have a test protocol based on physical/mechanical tests and corrosion tests. However, for this specific case, it did not suffice. Thus, a specific test was developed for washing tanks, which can evaluate simultaneously both corrosion and mechanical properties. This paper presents the development of a new test to simulate the behavior of paint systems submitted to cyclic tension in coatings in very corrosive environments (high salinity, CO2, and high temperature).10022 Corrosion Under Insulation-Testing of Protective Systems at High Temperatures保温层下腐蚀–高温下保护系统的测试作者：Kristian Haraldsen页数：11页Corrosion under insulation (CUI) has been a continuous challenge for on- andoff-shore installations, requiring continuous focus on maintenance work. Pilot scale accelerated testing has been performed to study and evaluate the effects of CUI on different coating systems and service conditions. A test loop has been constructed, where 115 mm o.d. pipe spools were combined in a loop which is internally heated using steam. The coated and insulated pipe spools were exposed at controlled internal temperatures and intermittently wetted by fresh seawater. Two test lines with 8 pipe spools have been run in parallel. Different aspects of CUI, including methods of steel pretreatment, coating application conditions, coating types and insulation design have been studied. Special focus has been on high temperature service conditions and the effect of moist and intermittently wet condition. High temperature coatings have been compared with a traditional coating system and thermally sprayed aluminum coating. The effect of coating application during service with steel temperatures up to 150°C has been studied. Due to the harsh exposure conditions, both tested coating systems were heavily degraded and a fair comparison of the coating systems is difficult. A positive effect of distance insulation was the most significant result from the test, and both tested coating systems showed markedly improved quality using distance insulation. The different application temperatures showed significant differences, and the results were in general better for the coatings applied at ambient conditions. Only minor differences were observed between the different steel pre-treatment methods. 10069 Finding and Determining the Cause of External Corrosion on Coated and Cathodically Protected Pipelines查找并确定实施阴极保护的防腐管道外腐蚀的原因作者：Richard Norsworthy页数：10页Direct Assessment is a very good method of determining if external corrosion is a potential problem on a coated and cathodically protected pipeline. The type of coating can be critical in finding where and if external corrosion is a problem. Many times external corrosion can not be located through over the line surveys because cathodic protection potentials indicate adequate protection, therefore there should be no external corrosion, yet internal line inspection (ILI) tools find corrosion. Many times the cause and age of the corrosion are not properly evaluated when performing direct assessment of these pipelines. This paper will discuss common sense evaluation methods for determining why external corrosion still exists and in some cases continues even with apparent adequate cathodic protection.10263 Wear Resistant Coating for Downhole Tubulars and Tools井下油管与工具的耐磨涂层作者：Joe L. Scott, Abbe Doering and Grant R. Folkmann页数：12页The oil and gas industry has long been in need of a wear mitigation solution for the tube body of drill pipe that did not manifest the metallurgical problems of welding.Thermal spray provides an alternative application method to welding, but is typically limited to very thin deposits (1mm or less) and is most often associated with corrosion resistance rather than wear resistance. A new coating has been developed that is wear resistant, robust and is capable of being applied in very thick deposits, from 0.010 inches up to 3.0 inches (.25 – 76 mm). This material has been applied to the body of drill pipe without any deleterious effect to the pipe, and the coating is being used to create centralizers and stabilizers for casing drilling and casing running, as well as other selected areas on down-hole tools and devices. This paper examines: the coating/deposit properties; application of the coating onto a substrate; and certain industrial exploitations of the coating.10265 High Corrosion Resistant Metallic Coatings for Oilfield Applications Exposed to Aggressive Environments暴露于侵蚀性环境的油田用高度耐腐蚀金属镀层作者：Haralampos Tsaprailis, Joshua Tuggle, Steven Waters, William Kovacs III, and Luis Garfias-Mesias页数：13页Highly corrosion resistance alloys (HCRAs) are becoming more popular for oilfield applications, where not only corrosion resistance is important, but also mechanical integrity and long term reliability. These materials are often exposed to a wide variety of aggressive environments that can range from marine splash zone to down-hole sour environments. The fabrication of these HCRAs metallic coatings typically involves coating low grade carbon steels with one or different layers of the HCRAs using techniques such as thermal spray coating, chemical vapor deposition, weld overlay, electrodeposition, etc. Previous work by the authors has described a novel testing methodology, based on the zero resistance amperometry (ZRA), which allows the determination of the critical pitting temperature (CPT) as well as the critical crevice temperature (CCT) in small angular sectioned samples taken from actual production hydraulic cylinders. In this paper, the CPT and CCT measurements that were successfully employed for evaluating UNS N06625 weld overlay materials compared with two potential HCRAs coated steels (UNS R31233 and UNS W73021). The main objective was to develop a rapid approach for the relative ranking of these materials for aggressive offshore applications. From the results obtained in this work, it is expected that the UNS W73021 weld overlay should have relatively better performance than the UNS N06625 weld overlays, which is expected to have relatively better performance than the R31233 weld overlays.09009 Heavy Duty Glass flake Coatings for Arduous Anti-Corrosion Service艰难的防腐场合用的重型玻璃鳞片作者：Charles Watkinson页数：18页Glass flakes have been used for a number of years to reduce gas and moisture vapourdiffusion through coating and paint films. Advances in glass flake production over more recent years, have allowed thinner and more consistent flakes to be produced. This has led to investigative work into the properties that can be attained by way of using glass flake as a performance improver. The work has investigated many materials both organic and inorganic and in many areas of use - such as lyres and even cosmetics. But, the biggest field of application is in organic resinous materials, not least of which, are those used in the area of corrosion protection for arduous service. Surprisingly, although the thin flakes (below 2 microns) are better performance improvers in most applications in some applications thick flakes (over 5 microns) are found to give better results. The high aspect ratio of a flake compared to fibres or granular fillers imparts unique properties to materials to which they are added but great care has to be taken in choosing addition level, thickness and size distribution to obtain the required result and for the optimisation of a particular characteristic. This work is tedious, time consuming and expensive but endeavour and patience can be amply rewarded.09012 Advancements in High Performance Zinc Epoxy Coatings高性能锌环氧涂料的进展作者：Lars Thorslund Pedersen页数：10页The present work investigates the use of alloyed zinc powders in zinc epoxy and zinc silicate coatings. It is found that small amounts bismuth have a dramatic effect on rust creep resistance while nickel and magnesium was not found to have any effect in the tested range. 0.5% bismuth in the zinc reduces rust creep by up to 80% after cyclic exposure according to ISO20340. With the alloyed zinc it is possible to formulate zinc epoxy coatings with rust creep below 1 mm in the test, thus achieving performance similar to what is know from zinc silicates.09013 A Ballast Tank Coating Inspection Data Management System压载舱涂层检验数据管理系统作者：Michael Sellers, J.F. Fletcher and Raouf Kattan页数：12页The coating process has long been considered to have less importance than other engineering activities that go into the manufacture and maintenance of a ship. This is often reflected by the relatively slow development in coating and surface preparation technology in comparison to other shipyard engineering processes, and the lack of hard data about the installation and subsequent maintenance of the system. The entry into force of the IMO MSC.216(82), more commonly referred to as the Performance Standard for Protective Coatings (PSPC) is challenging the status quo. Firstly by making the application and performance of the water ballast tank coating system subject to Safety of Life at Sea (SOLAS) regulations. This implies that poor performance of the coating system in the ballast tanks could result in a condition of。
ASMEB31G-2009在管道剩余强度计算中的应用
ASME B31G-2009在管道剩余强度计算中的应用1 引言近年来我国油气管道腐蚀现象日趋严重，由腐蚀造成的管道泄漏事故危害重大，因此，对腐蚀管道进行剩余强度评价极为重要。
对于含缺陷管道的剩余强度评价通常分为三种：采用断裂力学方法进行评价；采用以弹塑性力学为基础的数值分析方法进行评价；采用断裂力学和工程实践经验相结合的半经验公式进行评价。
20世纪60年代末，国内外一直在进行管道剩余强度评价方面的研究，多个国家颁布了相关的评价标准及规范。
1984年美国机械工程师协会颁布的ASMEB31G—1984标准是研究腐蚀管道剩余强度评价方面使用最广泛、最基本的评价标准之一，之后又推出了ASME B31G—1991修改版及改进的RSTRENG方法。
在应用的过程中，针对ASME B31G-1984评价准则的保守性，有关学者在1989年对ASME B31G-1984准则进行了修正，得到了ASME B31G-1991评价准则，该准则消除了原准则的一些不足。
2 ASME B31G-2009评价准则美国机械工程师协会于2009年更新了ASME B31G评价准则，即ASME B31G-2009，该评价准则延续并完善了之前的评价准则，但是提出了分级评价的概念，认为在应用该方法时，应根据实际情况选择不同等级的评价方法，使评价过程更为细化[1]。
2.1 零级评价为一系列查询表格，根据测量的腐蚀缺陷深度、管径、壁厚等参数，查询表格可以得到此缺陷最大允许长度，若实际腐蚀长度小于该极限长度，则缺陷处于安全状态，反之则表示没有通过评价，应采取维修措施或选择更高级别的评价方法。
该表格基本是根据原版的ASME B31G 评价方程计算得到的，只是增加了公制单位。
零级评价具有方便现场人员查阅、操作简单的特点，但其评价结果保守性较大。
2.2 一级评价ASME B31G-2009 推荐借助改进的B31G 评价方程来计算缺陷的剩余强度，该级评价应由相应的工程师、腐蚀技术人员或涂层检验人员来完成。
管道腐蚀与防护
外加电流阴极保护
-为了避免与牺牲阳极相关的驱动电压限制，可以将来自 外电源的电流通过地床和电源强制性地施加在管线上。 最常用的电源是整流器，该装置把交流电转化为低压直 流电，整流器常常配备有在合理范围内精细调节直流输 出的功能。 - 阴极保护需要有一个直流电源和一个辅助阳极，放置在 距保护构件一定距离的位置上。 - 直流电源的正极连接辅助阳极，负极连接需要保护的构 件（管道）。 - 电流从辅助阳极流出，经电解质到达管道表面（破损 处），再流回电源的负极。
在一般情况下，牺牲阳极提供的电流是有限的。所以，牺 牲阳极阴极保护一般都用在保护所需电流较小的情况下。 同样，管道钢材和牺牲阳极金属之间的驱动电压也是有限 的。因此，阳极和土壤之间的接触电阻必须很低以使阳极 输出有用数量的电流。这也就意味着在一般安装中，牺牲 阳极用于低电阻率土壤中。
常用的牺牲阳极有镁（Mg)阳极和锌(Zn)阳极
补口材料
（1）概念 补口（weld coating）：现场防腐成品管焊接后对 焊口进行防腐保护，通常叫做补口。一般补口 用材料有：收缩套（带），冷缠带，环氧涂层 或是煤沥青；其作用主要是用来进行焊口的防 腐。 根据涂层系统相容配套的原则，补口材料选择 时应考虑与管道运行环境及主体涂层的适应性 和兼容性好，可靠性高，寿命长。
多 层 环 氧 / 低的保护电流需要量，高的抗 挤出聚烯烃 阴极剥离能力，与钢材优异的 系统 黏结性，高抗冲击和磨损性能
原始投入高，可能对 阴保电流造成屏蔽
三层PE防腐层
采用聚乙烯对钢管进行防腐，是近年来逐步 推广开来的一种钢管防腐技术。聚乙烯涂层 的主要特点是： • 防腐性能极佳，可耐受在自然环境下存在的 各种腐蚀； • 具有较高的质价比； • 绝缘性能极好，而且在干燥条件下与长期浸 水条件下电性能基本不变，可有效的防止杂 散电流引起的电化学腐蚀；
管线腐蚀 pipeline_corrosion--Stress Engineering Service Inc
Pipeline CorrosionCorrosion Basics:Metals are normally found in nature in one their lowest energy states - usually as oxides, sulfides, chlorides, etc. In reducing and refining metals to produce useful alloys (such as the carbon and low alloy steels used in gas and oil transmission pipelines), significant amounts of energy are consumed and “stored” within the reduced metallic structures. Subsequent corrosion of steel pipelines thus represents the natural tendency of the iron in the pipe to return to a preferred, lower energy state (usually as an oxide, carbonate or sulfide).Corrosion of steel - at the relatively low temperatures (less than 200 degrees F.) normally encountered in pipeline operations – takes place by an electrochemical process. This process, in turn, requires the presence of anodic and cathodic areas on the surface of the pipe and the presence of a suitable, conductive aqueous environment that contacts both the anodic and cathodic areas. For buried pipe, the external corrosion environment will usually consist of moist, relatively high conductivity soil. Internal corrosion can occur if water exists within the line and is allowed to accumulate at low spots in the line. Significant internal corrosion also usually requires the presence of a significant partial pressure of carbon dioxide and/or oxygen within the line.The consumption of the steel pipe occurs at the anodic areas on its surface by oxidation of the iron of the pipe wall. The anodic portion of the corrosion process can thus be represented by equation (1):Fe → Fe++ + 2e-(1)The cathodic portion of the electrochemical corrosion process may reportedly occur by one of several reactions, depending upon the conditions of the environment:O2 + 2H2O + 4e-→ 4OH-(2)O2 + 4Η+ + 4e-→ 2H2O(3)2H2O + 2e-→ 2OH- + H2(4)H+ + e-→ _ H2(5)The ultimate fate of the Fe++ ion from equation (1) also depends upon the environment. The Fe may stay in solution as the ion or it may be precipitated as Fe(OH)2 or as FeCO3. For external corrosion in moist soils, the ultimate corrosion product is usually Fe(OH)2, while internal corrosion involving carbon dioxide often results in FeCO3 as a corrosion product.The kinetics of the electrochemical process can be shown schematically using the diagram in Figure 1. The open circuit potentials of the local cathodes and anodes, Φc and ΦA , are shown on the diagram, along with the polarization paths for the cathodes and anodes that result as increasing amounts of current are produced by the local electrodes. The over-all (average) corrosion potential for a surface covered with small, adjacent local anodes and cathodes (in a solution with moderate to high conductivity) thus occurs where the polarization curves for the electrodes approach one another, as shown in Figure 1.A similar diagram, as shown in Figure 2, can be used to illustrate the basic characteristics of corrosion prevention using cathodic polarization. The diagram in Figure 2 shows the continuation of the cathodic polarization curve that occurs as increasing amounts of positive current are forced onto the initially freely corroding sample surface (line c – e – f).Consider the situation at point e. At this point, the total current being supplied to the surface, I e , consists of the sum of the current being supplied from local anodes, I b , and the current being supplied from an outside voltage source, I e – I b .As the cathodic polarization of the sample surface is increased to point f, all current from the local anodes has been shut off and all of the current flowing to the sample surface is coming from the external applied voltage source.It should be noted that at point e, the sample surface is experiencing only partial protection from the applied current, I e – I b , that is being forced onto its surface. Some corrosion (as indicated by the anodic current, I b ) is still occurring on the sample surface. The sample becomes fully protected only after the polarized potential of the sample has dropped to ΦA and the anodic contribution to the total sample current has dropped to zero.It should also be noted, however, that continued polarization of the sample surface, to potentials more negative than ΦA, has no additional beneficial effects in preventing corrosion and may, instead, cause difficulties due to hydrogen-induced disbonding of coatings and hydrogen induced cracking of the steel of the pipeline.Corrosion Prevention:External corrosionThe principal methods used to prevent external corrosion of pipelines are coatings and cathodic protection (CP) of the lines. In recent installations, coatings and CP have normally been used together in a complimentary fashion, since high quality coatings substantially reduce the CP current requirements and the application of a functioning CP system allows some relaxation in the requirement for 100% “holiday” (defect) free coatings.Coatings:The NACE Standard RP0169-96 [1] lists most of the desirable characteristics of a pipeline coating. These include the following:1.The coating should have a high electrical resistance and high dielectric strength.2.The coating should be an effective moisture barrier.3.The coating should be reasonably easy to apply and the application process should notchange the properties of the pipe.4.The coating should exhibit good adhesion to the pipe.5.The coating should be resistant to chemical and physical damage/degradation duringinstallation and service.6.The coating should be reasonably easy to repair in the field.7.The use of the coating should not present any environmental or health risks.Pipeline coatings have been used for more than 70 years and numerous systems have been developed. The coating systems that are currently being applied include the following:1.Coal tar enamels containing embedded glass fiber mats.l-applied tape systems.3.Extruded polyethylene and polypropylene coatings.4.Fusion – bonded epoxy (FBE) coatings.5.Multi-layer, FBE under extruded polyethylene or polypropylene.The last three coating systems listed above are reportedly currently experiencing increasing acceptance by consumers and their future use should therefore expand.Cathodic Protection:The electrochemical basis for cathodic protection systems was presented briefly above in the Corrosion Basics section (see Figure 2). The current used to cathodically polarize the sample to be protected can typically come from an “impressed current” system using an external, D.C. power supply that supplies current to the pipe by way of a remote anode “ground bed”. Alternatively, the protective current can come from a reactive, “galvanic” anode or group ofanodes. Galvanic anodes are typically located within ten to twenty feet of the spot on the pipe to be protected.A schematic representation of a typical impressed current, cathodic protection system is shown in Figure 3. The anodes in the ground bed are usually made of graphite or high alloy cast iron rods. The rectifier that serves as the source of the polarizing current may have a voltage range of 10 to 100 volts and an available D.C. current range of 5 to 200 amperes.Since positive current flows from the positive to the negative terminal of the power supply in an external circuit that is connected to a D.C. power supply, it is critical that the pipeline to be protected be connected to the negative terminal of the rectifier. Connection of the pipeline to the positive terminal of the rectifier would result in greatly accelerated corrosion of the line (instead of the planned reduction/elimination of corrosion).The kinetics of the cathodic protection process when using a sacrificial, ganvanic anode are illustrated in Figure 4. The sacrificial or galvanic anodes are typically fabricated of relatively pure zinc or magnesium or alloys of these reactive metals. The polarized potential of typical zinc anodes is approximately –1.1 volts (as measured using a saturated copper – copper sulfate reference electrode - CSE). The polarized potential of a typical magnesium alloy anode is, on the other hand, approximately –1.50 to –1.55 volts vs. a CSE. The available driving potentials from the sacrificial anodes for polarizing steel structures are, therefore, relatively limited, and the length of pipe that can be protected using sacrificial anodes is relatively small.The three primary inspection criteria currently used to assess if appropriate levels of cathodic protection (CP) are being supplied to protected piping by a CP system are also described in NACE Standard RP0169-96. These criteria are:1. A piping potential of –850 mV vs. a CSE, measured with the CP system in operation.2. A polarized piping potential of –850 mV vs. a CSE, as measured within approximately 1/2 to1 second after (simultaneously) turning off all sources of direct current to the piping.3.100 mV of polarization with respect to the native corrosion potential of the pipe. Thepolarized potential used in this evaluation criterion is the same “instant off” polarization used in criterion 2.In using criterion #1, it is recognized by NACE that there are IR drop errors in the potential measurements that must somehow be estimated and evaluated in applying this criterion. There are no firm guidelines presented, however, on how this estimation and evaluation should be performed.In making the measurements involved in criteria #2 and #3, the IR drop errors caused by the flow of D.C. current to the protected structure are eliminated by measuring the polarized potential of the structure or piping within a half to one second after simultaneously shutting off all D.C.current sources to the structure or piping. There may, of course, be considerable difficulty and expense in finding and arranging for the simultaneous interruption of all D.C. currents to the piping and failure to eliminate these sources of current will result in errors in the measurements. In using criterion #3, the measurement or estimation of the “native” corrosion potential of the existing pipe or structure may also present some difficulties. For new piping that has not been previously protected by a CP system, it is only necessary to measure the initial “native”corrosion potential and then turn the CP system on and wait for the potential of the piping to drop to a stable value. At this point, switching off the source of all D.C. currents allows the measurement of the “instant off” polarized potential of the pipe and the shift in potential with respect to the original native potential.For existing piping that is currently under the protection of a CP system, shutting off all D.C. currents will allow the measurement of the “instant off” polarized potential of the pipe. A considerable waiting period (and some significant opportunity for error) may, on the other hand, be encountered in obtaining an estimate of the “native” corrosion potential in this case. Unfortunately, previously used piping systems that have been under the influence of a CP system for some extensive period are typically the objects of a CP system evaluation.Care must be taken during the installation and/or adjustment of CP systems to insure that the applied CP voltage is neither too low nor too high.Applied voltages that are too low could, of course, result in some corrosion to the piping. Also, there is some evidence that the high pH, stress corrosion cracking that is sometimes seen on the external surfaces of pipelines occurs in the range of lower polarized potentials (from approximately –0.50 and –0.85 volts vs. a CSE).In addition, elevated temperatures in the pipe are known to promote corrosion of the pipe. For piping or piping areas that operate at temperatures significantly above the surrounding earth temperature, an operating CP potential of –0.95 volts or more should be considered. The presence of bacteria in the soil may also promote the presence of microbiologically induced corrosion (MIC) on the outside surface of pipelines. In areas where MIC is suspected or confirmed, a CP potential of -0.95 volts or more should be considered.On the other hand, CP voltages that are larger than approximately –1.05 to –1.10 volts are thought to cause hydrogen induced cracking of some pipeline steels (particularly older steels containing higher levels of sulfur and phosphorus). This hydrogen induced cracking appears to be greatest in hard spots produced in the pipe during manufacture and in the heat affected zone of welds where small, localized hard areas may be present.Finally, elevated CP voltages may cause hydrogen-induced damage of coatings. It is generally recommended that CP voltages larger than approximately –1.10 volts be avoided in order to minimize the possibility of coating damage due to evolution of hydrogen.Internal CorrosionInternal corrosion in a pipeline requires the presence of liquid water within the line. In gas transmission lines (the only pipelines that will be discussed in this document), internal corrosion also usually signals the presence of significant partial pressures of carbon dioxide and/or hydrogen sulfide in the line.It is also known, however, that on a weight percentage or weight fraction basis, dissolved oxygen is more corrosive to ordinary steels than either carbon dioxide or hydrogen sulfide. Although the probability of having appreciable concentrations of oxygen inside a gas transmission line is apparently quite low, it should be remembered that even small partial pressures of oxygen can produce surprisingly high internal corrosion rates in steel pipes that also contain liquid water. One method to reduce the danger of internal corrosion by the acid gases, carbon dioxide and hydrogen sulfide, is to reduce the concentration of the acid gases in the gas transmission stream by a process known as “gas sweetening”. Many gas sweetening processes have been developed and used. These include, for example:1.Solid bed absorption (using iron sponge, mole sieves or zinc oxide),2.Chemical solvents (such as mono ethanol amine, di ethanol amine, potassium carbonate, etc),3.Proprietary physical solvents,4.Conversion of hydrogen sulfide to sulfur,5.Distillation.Water can form in a pipeline if there has been no attempt to dehydrate the gas prior to its introduction into the line or if the gas dehydration process that was used did not produce water contents in the gas that were low enough to prevent condensation of liquid water in the line. If the gas temperature drops below its water dew point, liquid water will probably form. Liquid water that is produced in the line will, of course, tend to accumulate in the low points in the line. Here, the water will equilibrate with carbon dioxide and/or hydrogen sulfide in the gas and can produce local areas of high internal corrosion rates.A second effective method used to prevent internal corrosion of gas transmission pipelines is thus dehydration of the gas prior to its introduction into the line. The aim of the dehydration process is to reduce the water content of the gas to a low enough level that the water will not condense in the line under the lowest pressure and temperature that the gas will experience in the line.By far the most common dehydration process for natural gas involves contacting the gas with a hygroscopic liquid such as a glycol. The most common glycol used for gas dehydration istriethylene glycol. The dehydration process takes place in a multi-tray column known as a glycol contactor. The glycol is “regenerated” before recycling to the contactor by heating to drive out the absorbed water. Glycol dehydration can usually easily reduce the dew point of the gas to the level required to prevent water condensation during transmission.The use of gas sweetening in conjunction with gas dehydration will, of course, minimize the chance of problems with internal corrosion in gas pipelines.Early work by de Waard and coworkers at Shell [2,3,4,5] resulted in what has come to be known as the “Shell” model for predicting the corrosion rates of steel by carbon dioxide. For example, the “Nomogram for CO2 Corrosion”, shown in Figure 5, allows easy estimation of the predicted corrosion rate of steel at various temperatures and carbon dioxide partial pressures. The combined effects of temperature and carbon dioxide partial pressure on the anticipated corrosion rates are shown in Figure 6. It should be pointed out that the “Shell” model is generally felt to be moderately to substantially conservative. For example, the model was developed for “clean”systems (containing no oil or other liquid hydrocarbons) and the presence of condensed hydrocarbons may substantially reduce the observed corrosion rates.In contrast to the weight loss corrosion problems produced by carbon dioxide, hydrogen sulfide (at the relatively low temperatures encountered in gas pipeline operations) generally causes environmental cracking (sulfide stress cracking, SCC) problems rather than weight loss corrosion. Guidelines for the selection of candidate materials for use in hydrogen sulfide environments (sour environments) are given in NACE Standard MR0175-2000 [6]. The concentrations of hydrogen sulfide above which the gas stream should be considered “sour” (and the threshold concentrations which will thus probably cause SCC) are also defined in NACE MR0175-2000 (see Figure 7 below).Corrosion Monitoring:External CorrosionSurvey methods that are commonly used to evaluate the external corrosion conditions of pipelines include:1.Pipe-to-soil potential measurements,2.Soil resistivity measurements,3.Measurements of D.C. currents flowing along the pipeline,4.“Bellhole” examinations of the pipe.Pipe-to-soil potential measurements are typically made using a saturated copper-copper sulfate (CSE) reference electrode that is placed in contact with the soil directly over the line. The potential measurements are made with a high input impedance voltmeter. Hooking the negative terminal of the voltmeter to the CSE electrode and the positive terminal to the pipeline gives readings with the normally used sign convention (e.g., the native corrosion potential of bare steel in moist soil will normally read between –0.1 and –0.5 volts).In pipe-to-soil potential surveys of pipe that is not under cathodic protection (and that has been allowed to reach its “native” corrosion potential prior to starting the measurements), the points on the line with the largest negative potential values will normally be the areas with the highest corrosion rates. Newly installed pipe (and pipe sections) will, however, usually have pipe-to-soil potentials that are substantially more negative than older sections of line and the pipe-to-soil potentials of new pipelines (without CP) will usually tend to decrease in magnitude (become less negative) with the passage of time.In applying pipe-to-soil potential measurements to pipelines under CP, one of the three primary acceptance criteria given in NACE Standard RP-01-69 (and discussed above) can be used. An example of actual pipe-to-soil potential measurements taken from the literature [7] is given in Figure 8. As shown by the upper curve in Figure 8, the section of pipeline represented in the figure would have satisfied criterion # 1 (-0.850 V vs. CSE with the CP system on). The pipeline would not, however, have satisfied criterion # 2 (a -0.850 V, “instant off” polarized potential). This criterion is represented by the intermediate curve in Figure 8. As can be seen, the section of the pipe between 0 and approximately 150 meters in the plot had a polarized potential that was smaller (less negative) than the required – 0.850 V vs. CSE. By subtracting the bottom curve (the native corrosion potential curve) from the intermediate curve (the instant off polarized potential curve), it can be seen that most of the pipeline also failed to meet criterion # 3. The calculated differences between the intermediate curve and the lower curve in the figure appear to generally be smaller than the 100 mV required by criterion # 3.Soil resistivity measurements can be made using either two terminal or four terminal meters. Either an A.C. or D.C. power supply can be used in conjunction with an instrument that accurately measures the current and potential between the test electrodes. Four terminal instruments are usually used when larger soil areas are examined or when resistivities at a greater depths are desired.Corrosion rates of buried pipes are generally higher in lower resistivity (higher conductivity) soils. Guidelines correlating observed corrosion rates with soil resistivities have been developed. These guidelines are documented in Table 1. Because of the possibility of errors caused by voltage drops in the soil due to the flow of CP currents, it is recommended that soil resistivity measurements be made with CP systems shut off.Line current measurements are typically made using test stations that are installed at the time the pipe was laid. Electrical leads are connected to both ends of the pipe test span and these leads are subsequently used to measure the voltage drop across the test span. The electrical resistanceof the test span is then either estimated or measured and the net electrical current in the test span is calculated using Ohm’s law. The sign of the voltage drop indicates the direction of the current flow through the test span. In order to eliminate the effects of any active CP system, line current measurements should be made with those systems shut off.The currents detected in line current measurements are “long-line” currents that are typically caused by widely separated “macro” electrodes (e.g., different soil conditions along the line) or by interferences from “foreign” D.C. fields in the earth (such as those caused by an adjacent, unconnected CP system). “Long-line” currents are not caused by the local anodes and cathodes that produce the corrosion normally observed on the line. However, at the location(s) where “long line” currents leave the pipe, the resulting corrosion rates can be very high. For example calculation shows that, if only 10 milliamps of D.C. current leaves a pipe over an area of 1 square inch on the pipe surface, a corrosion penetration rate of approximately 700 mils (or about 0.7 inches) per year would be observed at that location.Internal CorrosionSuccessful monitoring of internal corrosion of pipelines is apparently significantly more difficult than monitoring of external corrosion, as discussed above. One method that may yield valuable information concerning the general internal condition of a line is to periodically run scraper pigs through the lines. Evaluating the quantity and composition of material that is removed from the line by the scraper pig may be useful in evaluating whether or not significant internal corrosion has been occurring in the line.The development and use of “smart pigs” may soon allow the successful simultaneous detection and monitoring of both external and internal corrosion/damage in pipelines. Measurement techniques that have been considered and/or used in previous “smart pig” development efforts include:1.Multi-“finger”, mechanical calipers that detect and record the effective internal radius of thepipe,2.Magnetic flux-leakage tools that may be configured to respond to both longitudinal andcircumferential defects in the pipe. These tools may also include high frequency eddy current sensors that can differentiate between internal and external damage,3.Ultrasonic tools that couple directly to the pipe wall through a surrounding liquid and thatmay measure either the internal radius or the wall thickness of the pipe,4.Ultrasonic tools that use electromagnetic acoustic transducers (EMATS) to evaluate thecondition of the pipe wall. These transducers use electromagnetic signals to generateultrasonic signals in the pipe wall. Future use of EMAT technology may eliminate many of the difficulties and short comings with direct coupling ultrasonic tools.Corrosion Economics:A recent review [8] of the economic effects of corrosion upon the U. S. economy has been published. The results of this review indicate that corrosion of metals and alloys costs U. S. companies (and consumers) a total of approximately $300 billion per year. The authors of this review (scientists at Battelle Institute and the National Institute of Standards and Technology) also concluded that approximately one third of these total costs (approximately $100 billion per year) could be significantly reduced or eliminated by the use of current best available corrosion prevention techniques and materials.In the review, it was estimated that the pipeline industry accounted for something less than 1 percent of the total industry-wide corrosion costs. This would thus probably put the total costs for corrosion in the pipeline industry somewhere in the range of $2 billion to $3 billion per year. It also thus seems possible that the use of improved materials and corrosion prevention techniques in the pipeline industry might reduce the total costs of corrosion in this industry by as much as $600 million to $900 million (by ~ 30%).In the case of the pipeline industry, as in several other industry segments, the authors of the review felt that, although the need for corrosion-related repairs and re-coating had apparently gone down in the recent past, the savings due to the drop in repairs had been essentially balanced by the use of more expensive original materials of construction.In our opinion, the development of more sensitive and more accurate inspection techniques (such as improved “smart pigs”) and the possible regulatory requirement for the use of these more sensitive inspection techniques could substantially increase the repair costs associated with the future operation of aging gas transmission pipelines.References1.NACE RP0169-96 “Control of External Corrosion on Underground or Submerged MetallicPiping Systems”.2. C. de Waard and D.E. Milliams, Carbonic Acid Cirrosion of Steel”, Corrosion, Vol. 31,1975.3. C. de Waard, U. Lotz and D.E. Milliams, “Predictive Model For CO2 Corrosion Engineeringin Wet Natural Gas Pipelines”, Corrosion, Vol. 47, 1991.4. C. de Waard and U. Lotz “Prediction of CO2 Corrosion of Carbon Steel”, Corrosion 93,Paper 69, 1993.5. C. de Waard, U. Lotz and A. Dugstad “Influence of Liquid Flow Velocity on CO2Corrosion”, Corrosion 95, 1995.6.NACE MR0175-2000 “Sulfide Stress Cracking Resistant Materials for Oilfield Equipment”.7.“Peabody’s Control of Pipeline Corrosion”, NACE, 2001.8.“Economic Effects of Metallic Corrosion in the United States: a 1995 Update”, BattelleInstitute, 1996.TABLE ICorrosion of Steel in SoilCorrosionArea Corrosion (mpy)Severity Resistivity (Ω- cm)Ave. of Several61Moderately1000 to 2000Soils CorrosiveTidal Marsh100Corrosive500 to 1000Clay137Very Less than 500CorrosiveSandy Loam21Mildly2000 to 10000CorrosiveDesert Sand5Noncorrosive Above 10000。
英文腐蚀试验报告
BryantTo: DaveComposite Technology Corporation2026 McGaw AvenueIrvine, CA 92614USASALT SPRAY CORROSION TEST ON1020 KCMIL ACCC/TW CONDUCTOR FOR COMPOSITE TECHNOLOGY CORPORATIONKinectrics North America Inc. Report No.: K-422024-RC-0007-R00December 3, 2004M. ColbertTransmission and Distribution Technologies Business1.0 INTRODUCTIONA Salt Spray Corrosion Test was performed on samples of A luminum C onductor, C omposite C ore – T rapezoidal W ires (ACCC/TW) conductor for Composite Technology Corporation (CTC). The conductor consists of a Composite Fiberglass/Carbon Fiber Core and annealed, trapezoidal aluminum alloy wires. The conductor was stranded by General Cable. The code name for conductor is 1020 kcmil ACCC/TW Custom Design (16 wire).The test was performed from February 20, 2004 to April 2, 2004 by Kinectrics North America Inc. personnel at 800 Kipling Avenue, Toronto, Ontario, M8Z 6C4, Canada.2.0 TEST OBJECTIVE AND STANDARDThe objective of the Salt Spray Corrosion Test was to observe the effects on the whole conductor and the composite core of the ACCC conductor when exposed to a salt spray atmosphere for 1000 hours. A “Drake” 795 kcmil ACSR was also tested for comparison purposes. It should be noted that the aluminum strands of the ACCC conductor are annealed and trapezoidal and those for the ACSR are hard drawn and round. The test was performed using an environmental chamber that complied with ASTM B117-03, “Standard Practice for Operating Salt Spray Apparatus”.PRIVATE INFORMATIONContents of this report shall not be disclosed without authority of the client.Kinectrics North America Inc., 800 Kipling Avenue, Toronto, Ontario, M8Z 6C43.0 TESTSET-UPThe chamber has a salt-solution reservoir that is capable of maintaining an adequate solution. There is equipment to atomize the salt-solution including suitable nozzles and compressed air to provide a uniform spray within the chamber. The temperature of the chamber can also be controlled. The facility used to perform the test was an Industrial Filter and Pump 411.3ACD salt spray chamber and is shown in Figure 1.The measuring instruments used in this test are listed in Appendix A.PROCEDURE4.0 TESTThe fog chamber was programmed to provide a finely divided, wet dense fog while the air supply to the atomizer was maintained at a relative humidity of 95% to 98%. The chamber air temperature was maintained at 35 °C ± 1. The salt solution was 5% concentration and was prepared by dissolving by weight, 5 +/-1 parts of de-mineralized salt in 95 parts of de-ionized water. The quantity of collected salt spray was maintained at between about 1.0 to 2.0 ml/hour, as measure by a collecting area of 80 square cm. The pH of the collected solution was maintained between 6.5 to 7.2, at 25ºC, by adding the appropriate amount of sodium hydroxide. The following samples were exposed to the salt spray for 1000 hours.- one (1) whole ACCC conductor sample.- one (1) intact composite core sample.- one (1) composite core sample split lengthwise in two to expose the cross-section.- one (1) whole ACSR conductor sample.All samples were cut to about 50 cm in length and were placed in the chamber with an angle 20°from vertical. They were exposed to a salt spray for 1000 hours. Prior to insertion into the chamber, the samples were gently wiped to remove any loose particles. Tie-wraps were used to hold both ends of the sample in place. Silicon rubber was used to seal the ends of the sample.A cross-sectional photo of the ACCC conductor is shown in Figure 2.RESULTS5.0 TESTPhotographs of the cable samples during the test in the chamber, before the test, and after the test are shown in Figures 3a, 3b, and 3c, respectively.The results for the weight of the samples before and after the salt spray test are shown in Table 1. There was no indication of loss of material.After completion of the test, observations and dissections were performed. The results are in Table 2, 3, and 4. Photographs are shown in Figures 4a to 6e.Table 1: Salt Spray Test Results for CTC 1020 ACCC-TW and Drake 795 ACSR ConductorsSample Weight BeforeInsertion(grams)Weight After1000 hours(grams)WeightDifference(grams)CTC – One Whole Conductor 758 758 0CTC – One Whole Core 65.503 67.546 +2.04CTC – Half a Core (whole core splitdown the middle)34.748 34.750 +0.002CTC – Half a Core (whole core splitdown the middle)32.101 32.119 +0.018795 ACSR – One Whole Conductor 821 823 +2The increase in weight of the ACSR was due to the salt deposits that had collected between the layers. The salt was concentrated at the bottom end.Table 2: CTC 1020 ACCC-TW - ConductorPhotographs Component Observations after Salt Spray TestBefore AfterOutside Aluminum Layer - was mostly dull in color (not shiny anymore)- showed some discolored (darkened) patches.Figure4aFigure4bInner Aluminum Layer(2nd layer) - showed no signs of discoloration and deterioration.- the oily film was no longer present.-Figure4cCore - showed no signs of deterioration.- the oily film was still present on the surface.-Figure4d Table 3: CTC 1020 ACCC-TW – Whole and Half Core OnlyPhotographsComponent Observations after Salt Spray TestBefore AfterWhole Core andHalf Core - did not appear to have been affected by the salt fogtest.- there were no signs of discoloration or deterioration.- there were no signs of softening of the material.Figure5a5cFigure5b5dTable 4: Drake 795 ACSR – ConductorPhotographs Component Observations after Salt Spray TestBefore After OutsideAluminumLayer- was dull (not shiny anymore), and showed somediscolored (darkened) patches.Figure6aFigure6b Inner AluminumLayer(2nd layer)- exhibited some surface discoloration and dulling.- the bottom end had collected white salt deposits.-Figure6cOuter SteelWires- showed some discoloration (darkening).- small amounts of salt deposits were spread throughoutthe surface.- the bottom end had collected white salt deposits.-Figure6d Core Steel Wire- showed some discoloring (darkening).- it had some small amounts of salt deposits spreadthroughout its surface.- the bottom end had collected white salt deposits.-Figure6ePrepared by:M. ColbertTechnologistTransmission and Distribution Technologies BusinessReviewed by:C.J. PonPrincipal EngineerTransmission and Distribution Technologies BusinessApproved by:Dr.J.KuffelGeneralManagerTransmission and Distribution Technologies BusinessMC:CJP:JKDISCLAIMERKinectrics North America Inc., has prepared this report in accordance with, and subject to, the terms and conditions of the contract between Kinectrics North America Inc. and Composite Technology Corporation.© Kinectrics North America Inc., 2004.Figure 1: Industrial Filter and Pump, Model 411.3ACD Salt Spray ChamberFigure 2: Cross-sectional photo of 1020 kcmil ACCC/TW Custom Design (16 wire).Figure 3a: Test Samples in Salt Spray ChamberFigure 3b: Test Samples ‘Untested’, BEFORE Salt Corrosion TestFigure 3c: Test Samples AFTER 1000 hours Salt Corrosion TestBEFORE Salt Corrosion TestAFTER Salt Corrosion TestAFTER Salt Corrosion TestAFTER Salt Corrosion TestBEFORE Salt Corrosion TestAFTER Salt Corrosion TestBEFORE Salt Corrosion TestAFTER Salt Corrosion TestBEFORE Salt Corrosion TestAFTER Salt Corrosion TestAFTER Salt Corrosion TestAFTER Salt Corrosion TestAFTER Salt Corrosion TestDISTRIBUTIONMr. D. C. Bryant (2) Composite Technology CorporationAvenueMcGaw2026Irvine, CA 92614USAMr. C. Pon Transmission and Distribution – KB104。
乙醇胺管道泵腐蚀腐蚀挂片论文
乙醇胺蒸氨塔塔底泵及进出口管线的腐蚀研究【摘要】本文所研究的对象是国内某企业乙醇胺生产装置中的蒸氨塔塔底泵及进出口管线的腐蚀。
该泵在实际生产中运行不上量,严重的制约着该套乙醇胺生产装置的正常运行。
在对该泵拆检时发现该泵出现了严重的腐蚀。
而在对该泵的进出口管道的测厚数据也可看出该泵的进出口管线也出现了不同程度的腐蚀现象,以管道弯头的腐蚀最为严重。
对于该泵及其进出口管线的腐蚀,本文通过理论分析与现场挂片实验相结合的方法,分析指出该装置产生腐蚀原因,并提出相关的防护措施。
通过对该装置的腐蚀原因分析,可得出,造成管道腐蚀的主要原因是乙醇胺的降解导致溶液的腐蚀性增大,而溶液中H2S、CO2、Cl-等杂质的存在不但会促进乙醇胺的降解,导致溶液的腐蚀性大大增加,还会对装置所用材料304不锈钢产生直接的腐蚀。
通过分析得出了泵气蚀的原因是由于泵所输送的物质温度在160℃到180℃的范围变化,而当介质温度上升到180℃时会导致介质的蒸汽压高于泵进口压力,使得泵出现气蚀。
而乙醇胺的发泡导致溶液中携带着气泡进入泵内加大了泵的腐蚀。
至于乙醇胺的发泡则是受到溶液中固体颗粒的含量、降解产物的含量、温度等因素的影响,管道中所设置的过滤器会使得溶液的搅动增大,增加乙... 更多还原【Abstract】 This paper analyzes the corrosion of the pumpand its import and export pipelines which in the bottom of adomestic enterprise ethanolamine ammonia production plant’s ethanolamine ammonia tower.In the actual production this pump cannot work normally, seriously restricting the normal operation of the equipment. When opens to this pump examines discovered that this pump presented the serious corrosion. From the pump import and export pipeline thickness measurement data can also be seen in the impo... 更多还原【关键词】乙醇胺；管道；泵；腐蚀；腐蚀挂片；【Key words】ethanolamine；pipes；pumps；corrosion；corrosion coupon；摘要3-5ABSTRACT 5-6第一章绪论11-211.1 课题背景11-151.1.1 国内乙醇胺的生产工艺11-131.1.2 国内乙醇胺的生产能力与消费情况13-151.2 装置相关腐蚀研究简介15-191.2.1 乙醇胺的腐蚀研究151.2.2 乙醇胺的发泡研究15-161.2.3 硫化氢腐蚀研究16-181.2.4 二氧化碳腐蚀研究18-191.3 课题的目的和意义19-201.4 本课题的主要内容20-21第二章装置工艺流程及腐蚀状况介绍21-332.1 装置的工艺流程简介21-252.1.1 装置概况212.1.2 装置工艺流程21-252.2 蒸氨塔塔底泵装置的构成及作用25-282.2.1 泵装置的工艺条件252.2.2 塔底泵的作用25-262.2.3 泵进出口管线的结构尺寸26-282.3 塔底泵装置介质及腐蚀状况28-332.3.1 介质及其杂质情况28-292.3.2 泵装置的腐蚀状况29-33第三章装置腐蚀原因研究33-503.1 不锈钢的耐蚀机理及腐蚀形式33-353.2 不锈钢钝化膜的破坏机理35-363.3 物料及其杂质的腐蚀机理36-403.3.1 CO_2-H_2S-H_2O腐蚀环境37-383.3.2 R_xNH_y-CO_2-H_2S-H_2O腐蚀环境38-393.3.3 氯离子对腐蚀的促进作用39-403.4 泵的汽蚀原因及影响因素40-453.4.1 泵汽蚀产生的原因分析41-433.4.2 物料发泡对泵腐蚀的影响43-453.5 管道弯头的腐蚀45-463.6 腐蚀的影响因素46-493.6.1 温度对腐蚀的影响46-473.6.2 杂质浓度对腐蚀的影响473.6.3 物料流速对腐蚀的影响47-493.6.4 管道中过滤器的影响493.7 本章小结49-50第四章管道弯头流态分析50-694.1 CFD及FLUENT软件简介50-514.2 基本的控制方程51-534.3 湍流模型53-554.4 管道弯头的流态分析55-684.4.1 现役弯头的流态分析55-584.4.2 增大直径后弯头流态分析58-614.4.3 不同弯曲半径弯头的流态分析61-634.4.4 焊缝对弯头内流体的影响63-664.4.5 弯头与盲三同的流态比较66-684.5 本章小结68-69第五章实验研究69-765.1 挂片的材料及挂片前的准备69-705.2 挂片的部位及工艺处理70-725.3 挂片的数据处理72-745.4 最小承压壁厚计算74-755.5 本章小结75-76第六章防护建议76-79第七章结论与展望79-80参考文献。
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Abstract The formation of ripples on the surface of materials subjected to small-angle impingement erosion has been widely observed. In order to determine the origin and development of surface ripples, ductile (stainless steels and copper-based alloys) and brittle (thermal spray ceramics and cermets) materials were eroded in laboratory and fields tests. Scanning electron microscopy investigation revealed that the predominant wear mechanisms were scratching in metallic alloys, spray particle break-out in ceramics and removal of the binding matrix in cermets. Despite substantial differences in erosion mechanism, all the materials tested formed ripple patterns on their surfaces. It was determined that the ripple size increases with time and can attain a steady state that reflects local fluid flow conditions. Cermets and ceramics display the onset of rippling under more severe erosive conditions than metals. Ripple formation can induce cavitation, particularly on the lee side of ridges. Tests using water free of solid particles also gave rise to ripples, thereby confirming the importance of flow in their formation. Several hypotheses and models are discussed with respect to the results and a model based on the interaction between eddies and surface profile is presented.
0 1992 - Elsevier Sequoia. All rinhts resewed
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have been found to be far from the above value [4]. Yalin [7] based his hypothesis on the formation of eddies rotating about the horizontal axis perpendicular to the flow direction. Here a systematic disturbance of the large turbulent eddies and thus flow velocity is considered to be caused by any geometrical discountinuity of the eroding surface. The specific autocorrelation functions between perturbations and frequency bands of velocity fluctuations are established. These statistical orders are assumed to govern formation and size of ripples. Carter et al. [3] studied the connection between erosion parameters and ripple characteristics. Individual impact craters interact to form a collection of depressions and ridges which subsequently result in the occurrence of repetitive ripples. The model proposes surface morphology generation based upon the production of embrittled ridges and wave crests which are induced by plastic flow and ablated by impact. Stringer and Wright [4] conducted experiments on gas-carried solid particle erosion of several alloys. Using scanning electron microscopy (SEM) observations, they proposed a hypothesis based on the development of an intrinsic equilibrium structure due to the Kelvin-Helmholtz instability, which implies formation of waves ahead of the stagnation point of incident jet. Ripples are formed from the coalescence of the material displaced by the flux of impacting erodents carried by re-entrant jet. Much of the reported research on solid particle impingement erosion has concentrated on gas as a carrier medium. Erosion by liquid carriers has largely been confined to slurries where the particle concentration is high and the velocity low relative to erosion in hydroelectric power plants [S]. The work of Wright and Shetty [9] and Graham and Ball [lo] are typical examples of erosion encountered in hydraulic machines of high fluid velocities and low particle concentrations. Because of the lack of sufficient work on ripple formation on hard surfaces, some researchers concluded the non-existence of the phenomenon in brittle materials. The aim of the present research was to study the erosion mechanisms of a variety of materials subjected to a wide range of conditions. For this purpose, laboratory test rigs and field hydraulic equipment was used. In this paper the formation of ripples in ductile and brittle materials is highlighted.
The formation of waves or ripples on the surface of materials subjected to low angle impingement erosion is a well-described phenomenon [l-4]. Several researchers have based the generation and development of ripples on flow instability and particle transport. Abrahamson [l) proposed that the establishment of a permanent periodic wave regime due to travelling jets was responsible for ripple formation. Thereby, an incident jet colliding obliquely with a surface splits in two: a salient jet which moves parallel to the surface in the same direction as the major component of the incident jet, and a re-entrant jet which moves parallel to the surface in the opposite direction. The penetrating action of the jet forms a depression surrounded by an elevated region. The interaction of the deformed surface with jet components results in the formation of waves of jets travelling over the specimen surface. Hunt [S) modified this hypothesis somewhat, suggesting that the waves arise as a result of ~elmholtz instability between the re-entrant jet and the surface along which it propagates. Reid [6] later discussed the circumstances under which such a profile develops and related interface waves generation to the Von Karman vortex sheet which implies an amplitude-to-wavelength ratio of 0.28. The experimental values of the amplitude-to-wavelength ratio of ripples