– During offshore pipe-lay, pipe lengths with anticorrosion coating are welded together, and, to facilitate the welding process, the ends of the pipe remain uncoated. A wide range of field joint coating (FJC) types is available for coating this bare section, functioning in conjunction with the pipeline cathodic protection system to provide an anti-corrosion system or package. This paper aims to relate to two-layer type heat shrink sleeves (2LHSS), which commonly are used for FJC of concrete-weighted offshore pipelines where the sleeve typically is over-coated with a solid or foam type polyurethane “infill”. Similar sleeves also are used sometimes in exposed conditions on lines without concrete over-coating. The maximum allowable soluble salt contamination prior to application of high-performance coating systems can vary, depending upon the coating type, but typically has been set at 20 mg/m2 (de la Fuenteet al., 2006). The first layer of three-layer heat shrink sleeve (3LHSS) systems for pipeline FJC, liquid epoxy, falls into this category (ISO_21809-3:2008, 2008). In contrast, the 2LHSS system does not use a liquid epoxy first layer but relies instead on the bonding of a “mastic” layer directly to the pipe metal surface. The maximum acceptable concentration of salt contamination on prepared metal surfaces prior to the application of 2LHSS has been a subject of debate and was the focus of this study. International standards for FJC do not provide a maximum salt level. However, some companies have continued to specify low thresholds for the maximum allowable salt level for 2LHSS, which can result in expensive delays in production during offshore pipe-lay. In this study, salt contamination levels of up to 120 mg/m2 were found to have no effect on peeling performance after accelerated aging by hot water immersion. Furthermore, preparation for welding and the use of potable water during ultrasonic testing procedures prior to FJC, typically reduces the salt contamination level to below 50 mg/m2 providing a strong case for the deletion of salt contamination testing for 2LHSS.

Corrosion resistant Fe – Al / Al 2 O 3 duplex coating for pipeline steel X80 was prepared by a combined treatment of low-temperature aluminizing and micro-arc oxidation (MAO). Phase composition and microstructure of mono-layer Fe – Al coating and Fe – Al / Al 2 O 3 duplex coating were studied by X-ray diffraction (XRD), scanning electron microscope (SEM) with energy dispersive spectrometer (EDS). Corrosion resistance of the coated pipeline steel X80 in a simulated oil and gas well condition was also investigated. Mono-layer Fe – Al coating consists of Fe 2 Al 5 and FeAl, which is a suitable transitional layer for the preparation of ceramic coating by MAO on the surface of pipeline steel X80. Under the same corrosion condition at 373 K for 168 h with 1 MPa CO 2 and 0.1 MPa H 2 S, corrosion weight loss rate of pipeline steel X80 with Fe – Al / Al 2 O 3 duplex coating decreased to 23% of original pipeline steel X80, which improved by 10% than that of pipeline steel X80 with mono-layer Fe – Al coating. It cannot find obvious cracks and pits on the corrosion surface of pipeline steel X80 with Fe – Al / Al 2 O 3 duplex coating.

External surfaces of pipelines are protected from corrosion by polymeric coatings that have evolved in the industry over the past 60 years, beginning with asphalt and then coal tar coatings, followed by polyethylene, epoxy, and urethane coatings. When a coating degrades or fails, the type of coating has an effect on the generation of environments that can cause corrosion and stress-corrosion cracking (SCC). In this paper, the types of coatings, laboratory performance, field performance, and the state-of-the-art of various pipeline coatings are reviewed.

The three-layer polyethylene (3PE or 3LPE) coatings have been widely used on long-distance high pressure transmission pipelines in China. The 3PE coating tends to remain high insulating after disbonding from pipelines, and block the function of cathoidc protection (CP), similar to PE tape coatings that caused stress corrosion cracking (SCC) failure of pipeline. Disbondment 3PE coatings have been reported worldwide. Because of the high integrity and dielectric strength of 3PE coatings, SCC under disbonded 3PE coating becomes an important issue for integrity management and operation of high pressure pipelines. A great deal of researches have been conducting over the past 20 years to reproduce SCC of high strength low alloy (HSLA) pipeline in laboratory. Most of these studies were conducted in bulk solution condition. The methodology neglects particularity of the thin-layer electrolyte under disbonded coating which has been identified as one of the primary environmental factors related to SCC. In this context, a research project has been initiated on this subject. The overall goal is to systematically investigate corrosion scenarios and mechanochemical interaction of HSLA pipeline steels under disbonded 3PE coating in different soil environments, particularly to further mechanistic understanding the initiation of SCC on pipelines under disbonded coating. In this work, SCC behavior of API X80 pipeline steel under disbonded coating with defect was investigated in acidic soil solution by a crevice cell specially designed for simulating coating disbondment. The crevice cell was equipped with a multi-sample loading frame, through which multi specimens in the crevice cell can be loaded simultaneously. Electrochemical impedance spectroscopy (EIS) was applied to characterize local electrochemical process of the tensile specimens. Local environment parameters (potential and pH) were monitored by microelectrodes. Surface morphology of the corrosion specimens indicate that corrosion intensity of X80 steel decreased over the distance from the opening. Intensive anodic dissolution and microcrack initiation were preferential at the opening defect, whereas corrosion was markedly mitigated under disbonded coating. CO2 content gradient is proposed for the special corrosion scenarios under coating disbondment.

设计加载阵列电极应力腐蚀实验装置, 针对我国典型的华南酸性红壤环境, 研究高强度低合金(HSLA) X80管线钢在破损防腐层(涂层)模拟缝隙下的应力腐蚀开裂(SCC)行为及影响因素, 采用电化学阻抗谱(EIS)监测加载电极的腐蚀电化学过程, 利用微电极监测防腐层剥离区局部电位和pH值变化, 探讨破损涂层下HSLA管线钢SCC行为和规律. 结果表明, 防腐层开放破损(漏点)处管线钢发生严重腐蚀: 不受力试样表面以阳极溶解占主导的均匀腐蚀为主, 而拉伸试样表面出现大量微裂纹和点蚀坑, 且沿试样划痕优先生长; 封闭的剥离区内部管线钢的腐蚀程度显著减缓. 同时, 对涂层破损点及剥离区深处管线钢的腐蚀现象和过程进行了讨论.

This study investigates the feasibility of identifying the axial position of circumferential defects in laminated pipeline structures based on damage indices. Wavelet packet decomposition is combined with damage indices, and the effects of dual defects with the same circumferential position but different axial positions, as well as dual defects with different circumferential and axial positions, on damage indices are separately studied. Our aim was to determine the potential to use damage indices to identify the axial position of circumferential defects in laminated pipeline structures. ABAQUS finite element analysis software was used to establish models of laminated pipeline structures with single defects and dual defects (with the same circumferential position but different axial positions, and with different circumferential and axial positions). The laminated pipeline structure was composed of a steel pipe (structural layer), a rigid polyurethane foam (insulation layer), and a high-density polyethylene (anticorrosion layer). The received sensing signals were averaged, and subjected to 5-level wavelet packet decomposition, to calculate the damage index values, which were then organized into a damage index matrix. Based on the trend of changes in the damage index matrix, the effects of variations in the number and circumferential position of the defects on the identification of the axial position of the damage were analyzed. The results indicate that the trend in damage index changes is influenced by the number of defects, and the increase in the circumferential distance between the second and the piezoelectric element sensor. This study found that when 1.7λ≤PD≤3.4λ, Idouble defect 90°<Isingle defect<Idouble defect 0°; when 3.7λ≤PD≤4λ, Idouble defect 90°<0.3<Idouble defect 0°<Isingle defect. This article demonstrates that the identification of the axial position of damage in laminated pipeline structures can be achieved using the damage index values in the damage index matrix. Additionally, this damage identification method overcomes the limitation of the wavelet packet’s inability to identify dual defects with relatively small relative axial distances. This provides new ideas and methods for finite element analysis in identifying the axial position of damage in laminated pipeline structures.