Search Results for Gas pipelines

On 9 March 2000, a gasoline pipeline failed near Greenville, TX releasing approximately 12,000 barrels of fuel. After the on-scene portion of the investigation was completed, an 8.5 ft. (2.6 m) section of the 28 in. (71 cm) diam pipe was sent to the materials laboratory for examination. Examination included optical and scanning electron microscopy of the fracture surfaces and metallographic examination of cross sections through the fracture surface. From the outer to inner edge of the fracture surface, three different areas were observed. Fracture features in area 1 were obliterated by corrosion. The fracture features in region 2 were relatively smooth, and striations were observed, typical of fatigue. In region 3, dimple features were observed, typical of ductile overstress. Also, corrosion pits were observed on the outer surface of the pipe section in locations where the protective black tar-like coating was cracked.

A high-density polyethylene (HDPE) natural gas distribution pipe (Grade PE 3306) failed by slow, stable crack growth while in residential service. The leak occurred at a location where a squeeze clamp had been used to close the pipe during maintenance. Failure analysis showed that the origin of the failure was a small surface crack in the inner pipe wall produced by the clamping. Fracture mechanics calculations confirmed that the suspected failure process would result in a failure time close to the actual time to failure. It was recommended that: materials be screened for susceptibility to the formation of the inner wall cracks since it was not found to occur in pipe typical of that currently being placed in service; pipes be re-rounded after clamp removal to minimize residual stresses which caused failure; and a metal reinforcing collar be placed around the squeeze location after clamp removal.

A natural gas pipeline explosion and subsequent fire significantly altered the pipeline steel microstructure, obscuring in part the primary cause of failure, namely, coating breakdown at a local hard spot in the steel. Chemical analysis was made on pieces cut from the portion of the pipe that did not fracture during the explosion and from piece 5-1 which contained the fracture origin site. Both pieces were found to have 0.30% carbon and 1.2% Mn with sulfur and phosphorus impurities acceptably low. Fracture mechanics analysis used in conjunction with fractographic results confirmed the existence of a very hard spot in the steel prior to the explosion, which was softened significantly in the ensuing fire. This finding allowed the micromechanism leading to fracture to be identified as hydrogen embrittlement resulting from cathodic charging.

This article discusses the failure analysis of several steel transmission pipeline failures, describes the causes and characteristics of specific pipeline failure modes, and introduces pipeline failure prevention and integrity management practices and methodologies. In addition, it covers the use of transmission pipeline in North America, discusses the procedures in pipeline failure analysis investigation, and provides a brief background on the most commonly observed pipeline flaws and degradation mechanisms. A case study related to hydrogen cracking and a hard spot is also presented.

A case of continual product refinement stimulated by product failures was described. Brittle fracture of gas transmission line pipe steels occurred demonstrating a poor combination of materials, environment, manufacturing and installation problems, and loads. Initial efforts were concentrated towards decreasing the Charpy ductile-to-brittle transition temperature to avoid brittle fracture. It was subsequently revealed that the absorbed energy on the upper shelf of the Charpy energy-temperature curve was critical for arresting a moving crack. Both fracture initiation and fracture propagation were needed be controlled. It was concluded that improved steel processing procedures, chiefly hot-working temperature and deformation control, were also required to optimize microstructure and properties.

This article describes the failure characteristics of high-pressure long-distance pipelines. It discusses the causes of pipeline failures and the procedures used to investigate them. The use of fracture mechanics in failure investigations and in developing remedial measures is also reviewed.

A welded natural gas line of 400 mm OD and 9 mm wall thickness made of unalloyed steel with 0.22C had to be removed from service after four months because of a pipe burst. Metallographic examination showed the pipe section located next to the gas entrance was permeated by cracks or blisters almost over its entire perimeter in agreement with the ultrasonic test results. Only the weld seam and a strip on each side of it were crack-free. Based on this investigation, the pipeline was taken out of service and reconstructed. To avoid such failures in the future, two preventative measures may be considered. One is to desulfurize the gas. Based on tests, however, the desulfurization would have to be carried very far to be successful. The second possibility is to dry the gas to such an extent as to prevent condensate, and this corrosion, from forming no matter how low winter temperatures may drop. This measure was ultimately recommended, deemed more effective and cheaper.

A wall section of a carbon steel choke body in gas service at 4400 psig blew out three months after the use of a corrosion inhibitor was stopped. Corrosion damage occurred in ripples, leaving both smoothly polished and unattacked areas. The corrodent in condensate wells was principally carbon dioxide dissolved in water condensed from the gas stream, with organic acids possibly an aggravating factor. A gas analysis showed no other corrosive agents. No metallurgical or fabrication defects were found in the carbon steel part. The mode of attack was corrosion-erosion, caused by the corrosive, high velocity gas flow. The corrosion rate of either the inhibited or uninhibited gas stream was too high for equipment in high pressure gas service. Type 410 (12% Cr) stainless steel was recommended for the choke bodies because other equipment such as valves made of type 410 showed no evidence of corrosion damage after three years' exposure. This change was made five years ago and there have been no failures since.

The silver layer on a thrust bearing face experienced electrostatic discharge attack (the bombardment of an in-line series of individual sparks onto the soft bearing face), which destroyed the integrity of the bearing surface. The electrical attack appeared as scratches to the naked eye. Macrophotography showed that the attack was more severe at one edge of each pad, resulting in deeper grooving and a buildup of deposits, mostly silver sulfides. Microstructural analysis of a cross section indicated that the interface between the silver overlay and the substrate (beryllium copper) was sound and free of voids and foreign material. Corrosion products contained a large quantity of sulfur. The probable cause of the attack was the presence of electrical current within the system, with sulfides a possible contributing factor. Elimination of residual magnetism and grounding of the rotating system at appropriate locations were recommended.

A ring-type joint in a reactor pipeline for a hydrocracker unit had failed. Cracks were observed on the flange and the associated ring gasket during an inspection following a periodic shutdown of the unit. The components were manufactured from stabilized grades of austenitic stainless steel; the flange from type 321, and the ring gasket from 347. Examination revealed that the failure occurred by transgranular stress-corrosion cracking, initiated by the presence of polythionic acid. Detailed metallurgical investigation was subsequently conducted to identify what may have caused the formation of polythionic acid in the process gas.

This article focuses on the mechanisms of microbially induced or influenced corrosion (MIC) of metallic materials as an introduction to the recognition, management, and prevention of microbiological corrosion failures in piping, tanks, heat exchangers, and cooling towers. It discusses the degradation of various protective systems, such as corrosion inhibitors and lubricants. The article describes the failure analysis of steel, iron, copper, aluminum, and their alloys. It also discusses the probes available to monitor conditions relevant to MIC in industrial systems and the sampling and analysis of conditions usually achieved by the installation of removable coupons in the target system. The article also explains the prevention and control strategies of MIC in industrial systems.

This article focuses on the mechanisms of microbiologically influenced corrosion as a basis for discussion on the diagnosis, management, and prevention of biological corrosion failures in piping, tanks, heat exchangers, and cooling towers. It begins with an overview of the scope of microbial activity and the corrosion process. Then, various mechanisms that influence corrosion in microorganisms are discussed. The focus is on the incremental activities needed to assess the role played by microorganisms, if any, in the overall scenario. The article presents a case study that illustrates opportunities to improve operating processes and procedures related to the management of system integrity. Industry experience with corrosion-resistant alloys of steel, copper, and aluminum is reviewed. The article ends with a discussion on monitoring and preventing microbiologically influenced corrosion failures.

The genesis of failure of 6.1 mm thick electric resistance welded API 5L X-46 pipes during pretesting at a pressure equivalent to 90% of specified minimum yield strength was investigated. Cracks were found to initiate on the outer surface of the pipes in the fusion zone and propagate along the through-thickness direction. The presence of extensive decarburization and formation of a soft ferrite band within the fusion zone may have contributed to the nucleation of the cracks. Crack propagation was aided by the presence of exogenous inclusions entrapped within the fusion zone. Analysis of these inclusions confirmed the presence of Fe, Si, Ca, and O, indicating slag entrapment to be the most probable culprit.

A section of pipe in a hydrocarbon pipeline was found to be leaking. The pipeline was installed several decades earlier and was protected by an external coating of extruded polyethylene and a cathodic protection system. The failed pipe section was made from API 5L X46 line pipe steel, approximately 22 cm (8.7 in.) OD x 0.5 cm (0.2 in.) wall thickness, which was electric resistance welded along the longitudinal seam. The pressure at the time and location of the failure was 2760 kPa, which corresponds to 20% of the specified minimum yield strength. The cause of failure (based on visual inspection, magnetic particle inspection, stereoscopic analysis, scanning electron microscopy, tensile and hardness testing, and chemical analysis) was attributed to damage resulting from a lightning strike.

A return bend (made from ASTM A213, grade T11, ferritic steel) from a triolefin-unit heater ruptured after two years in service. The unit operated at 2410 kPa, with a hydrocarbon feed stream (85% propylene) entering at 260 to 290 deg C and leaving at 425 to 480 deg C. The fracture was found to terminate at the welds that joined the bend to the pipeline. A high concentration of both small and large inclusions was exhibited by the metallographic examination of the steel near the fracture. Branched cracks similar to those produced by stress corrosion of steel were observed in a section through the fireside edge of the fracture surface. Scale was observed over most of the crack path which acted as a stress raiser. The effect of the oxide was magnified during thermal cycles because of differential thermal expansion, with the steel having a greater expansion coefficient than the scale. It was recommended that material that is intended for critical applications where failure cannot be tolerated should be non-destructively examined.

This article describes some of the welding discontinuities and flaws characterized by nondestructive examinations. It focuses on nondestructive inspection methods used in the welding industry. The sources of weld discontinuities and defects as they relate to service failures or rejection in new construction inspection are also discussed. The article discusses the types of base metal cracks and metallurgical weld cracking. The article discusses the processes involved in the analysis of in-service weld failures. It briefly reviews the general types of process-related discontinuities of arc welds. Mechanical and environmental failure origins related to other types of welding processes are also described. The article explains the cause and effects of process-related discontinuities including weld porosity, inclusions, incomplete fusion, and incomplete penetration. Different fitness-for-service assessment methodologies for calculating allowable or critical flaw sizes are also discussed.

Erosion of a solid surface can be brought about by liquid droplet impingement (LDI), which is defined as "progressive loss of original material from a solid surface due to continued exposure to erosion by liquid droplets." In this article, the emphasis is placed on the damage mechanism of LDI erosion under the influence of a liquid film and surface roughness and on the prediction of LDI erosion. The fundamentals of LDI and processes involved in initiation of erosion are also discussed.

During the construction of a large-diam pipeline, several girth welds had to be cut out as a result of radiographic interpretation. The pipeline was constructed of 910 mm (36 in.) diam x 13 mm (0.5 in.) wall thickness grade X448 (x65) line pipe. The girth welds were fabricated using standard vertical down stove pipe-welding procedures with E7010 cellulosic electrodes. The crack started partially as a result of incomplete fusion on the pipe side wall, which in turn was a result of misalignment of the two pipes. The crack was typical of hydrogen cracking. Girth welds can be made using cellulosic electrodes. For high-risk girth welds, an increase in preheat and/or a reduction in the local stress by controlling lift height or depositing the hot pass locally before lifting may be required.

A bent Ni-Cu Monel 400 alloy tube, which operated as part of a pipeline in a petrochemical distillery, failed by through-thickness cracking. The pipeline was used to carry a stream of gaseous hydrocarbons containing hydrochloric acid (HCl) into a reaction tower. The tower provided a caustic solution (NaOH) to remove HCl from the stream, before the latter was directed to a burner. Metallographic examination showed that the cracks were intergranular and were frequently branched. Although nominal chemical composition of the component was found within the specified range, energy dispersive x-ray analysis (EDXA) indicated significant segregation of sulfur and chlorine along the grain boundaries. Failure was attributed to hypochlorous-acid (HClO)-induced stress-corrosion cracking (SCC). The HClO was formed by the reaction of HCl with atmospheric O 2 that entered the tube during shutdowns and startups. Residual stresses, originating from in situ bend forming of the tube during assembly of the line, provided a driving force for crack growth, and the segregation of sulfur on grain boundaries made the material more susceptible to cracking.