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This paper describes the relevant characteristics of available joint coating types and examines different testing protocols to explore these characteristics. The objective is to assist in the selection of appropriate, practical, cost effective girth weld protective coatings. that will provide good long-term corrosion protection.
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This paper aims to present a novel class of pipeline protective lining materials that provide erosion-corrosion resistance combined with negligible wear to spray equipment. These coatings have been formulated with a blend of thermoplastic fillers rather than the traditional ceramic fillers used for erosion resistance.
During the construction of a 56km long 16 in. carbon steel sour gas pipeline, repetitive surfacepreparation failures were detected during visual inspection of pipeline girth weld internal surface prior tocoating application. Such failures represented 67% of the total pipeline girth welds and were manifestedby excessive sharp-edges at the root pass. To identify the failure causes, an investigation wasperformed through reviewing the pipeline, fabrication and coating application specifications andprocedures, quality control records and performing an extensive visual inspection through an advancedvideo robotic crawler on all pipeline girth welds made. Upon investigation analysis, the failures werecaused by sharp-edges in the root pass which were attributed to improper practices duringmanufacturing, field fabrication and pre-coating quality control. The failure analysis indicated that themechanized Gas Metal Arc Welding process, with the parameters used, was not suitable for internalgirth weld coating application. In addition, a more stringent requirement should be applied to theacceptable pipe-end diameter tolerance and pre-coating quality control to ensure absence of similarpremature surface preparation failures. The pre-coating quality control can be improved throughutilization of robotic laser contour mapping crawler for precise detection and sizing of unsatisfactorysurface weldment defects, including sharp edges.
Pipelines have primarily been developed for the oil and gas business as well as building domestic water networks. To ensure the quality and longstanding pipelines, inspection and quality during design, construction and operations are of prime importance. During construction, pipe manufacturing and field fabrication represent the major cornerstone of a construction quality program.
NACE MR0175 / ISO 15156 document part 2 provides material requirements for selecting cast irons and low-alloy steels for sour environments.1 Figure 1 is reproduced from this standard and describes different regions of environmental severity for Sulfide Stress Cracking (SSC): service in region 0 being the least susceptible to cracking, even for very sensitive materials, and region 3 being the worst.
Asset owners, engineers, consultants, coating contractors, inspectors, and others are specifying allowable levels of surface soluble salts to prevent premature coating failures. The purpose of this standard is to provide guidance about the number of and locations for soluble salt tests on steel surfaces.
This standard establishes siting and frequency requirements for soluble salt testing before the application of a subsequent coating system to previously coated substrates and replacement substrate material. It does not include allowable limits of soluble salts, which are typically addressed by the procurement documents or the coating manufacturer’s documentation.
Seamless X60QOS and X65QOS line pipes are widely used for offshore and onshore Sour Service applications. Sour Service refers to the risk of hydrogen related cracking as Sulfide Stress Cracking (SSC). The International standard (NACE MR0175 / ISO 15156) provides requirements for assessing the resistance to SSC, specifically on how to qualify for use in region 3 of the environmental severity diagram (Figure 1 in paragraph 7.2.1.2 of part 2). It is requested to expose materials in an acid solution saturated by 1 bar of H2S (NACE TM0177 Solution A) and to apply a tensile stress above 80% AYS by means of different methods: uniaxial tensile, C-ring or Four-Points Bend. However, for very sour fields presenting H2S partial pressures much higher than 1 bar, the preservation of the SSC resistance might be questioned and is presently a major concern for the O&G industry.The present paper is dedicated to the evaluation of the SSC resistance of seamless quenched and tempered X65 grades, including the girth weld in the standard NACE TM0177 Solution A up to 15 bar of H2S partial pressure. Corrosion tests consisted of four-point bend tests performed in autoclave vessels. Different test configurations were investigated as specimen sampling locations through the wall thickness and surface state preparation.
Seamless X60QOS and X65QOS linepipes are widely used for Sour Service offshore and onshore applications. Sour Service refers to the risk of hydrogen related cracking, such as by Sulfide Stress Cracking (SSC). The International standard NACE MR0175 / ISO 15156 provides requirements for assessing the resistance to SSC, specifically on how to qualify for use in region 3 of the environmental severity diagram (Figure 1 in paragraph 7.2.1.2 of part 2). Qualification requires exposing materials in an acid solution saturated by 1 bar of H2S (NACE TM0177 Solution A) and to apply a tensile stress above 80% AYS by means of different methods: uniaxial tensile, C-ring or Four-Point Bend. However, for very sour fields presenting H2S partial pressures much greater than 1 bar, the preservation of the SSC resistance might be questioned and is presently a major concern for the O&G industry.
New gas field expansion will provide offshore facilities to process non-associated gas, where the newgas gathering system takes non-associated gas from offshore gas wells and transports it throughpipeline to onshore processing plants. The gas is very corrosive due to high levels of H2S and CO2 acidgases content. Further hydrate control is achieved by injecting mono ethylene glycol (MEG).