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ASME STP-PT-011-2008 pdf download

In the 40-year period since external stress-corrosion cracking (SCC) was first experienced in gas transmission pipelines, a considerable body of field experience has been obtained in North America. Some of this information has been published, but much more has been retained in company archives and used to develop in-company practices and procedures for managing the threat of SCC. With the advent of regulatory requirements for formal integrity management plans for gas transmission pipelines, it has been necessary to develop guidance for addressing SCC. Guidance such as that embodied in ASME B31.8S [1] has been based on the collective experience and knowledge of industry experts, incorporating such operational experience as was available at the time. For example, the ASME guidance on identifying which high consequence areas are SCC-susceptible is based on the information available five years ago. During recent years, a substantial amount of additional field knowledge has been obtained by gas pipeline operators. Hydrostatic testing programs and excavation programs have generated a large number of records, and in-line inspection (ILI) crack detection vehicles have been run on a developmental basis in several pipelines. Hence, it is timely to collate the information now becoming available and establish/confirm the patterns and trends that can be used to maximize the effectiveness of SCC Integrity Management Plans. The opportunity to undertake such an exercise has arisen during the ongoing Joint Industry Project (JIP) on “Management of Stress-Corrosion Cracking in High Consequence Areas.” This report collates the detailed records from SCC investigations (hydrostatic tests, excavations and ILI) made available by the JIP participants, and compares them with those seen in other published work. The resulting trends and patterns in field experience will be used to form the basis for guidance on the critical decisions to be made by operators during the implementation of their SCC management plans.
2.1 Data Provided by the JIP Participants and Other Operators All the JIP participants are operators of substantial systems for the transmission of dry natural gas in various locations in North America. All the JIP participants have some prior experience of SCC in their pipelines; in some instances this dates back to the earliest in-service ruptures and leaks in the mid-1960s. Experience spans both high pH and near-neutral pH SCC. During the course of the JIP, several other operators with similar operational experience of SCC offered detailed information for inclusion in the survey. This information has been added to that provided by the JIP participants and is included in the analyses presented below. All these operators have taken active steps to manage the threat of SCC. As a result, the individual operators have amassed substantial amounts of field information from hydrostatic testing, excavations and ILI, relevant to their individual operational needs. The information gathered from the JIP participants covers several types: Pipeline attribute information: Pipeline age, diameter and wall thickness Pipe grade and coating type Operating pressure
During this exercise, no attempt was made to collect information on the environmental, electrochemical and conditioning parameters that might correlate with the location and extent of cracking, such as coating degradation, CP system performance, terrain and soil texture/type. Similarly, no attempt was made to collect information relating to operating temperatures at or immediately downstream of compressor discharges. Previous work [2]-[6] has indicated the relevance of temperature to coating degradation and crack formation, particularly for high pH SCC. However the key information relates to historical operating practices, before operators reduced their compressor discharge temperatures in the 1980s, and this is extremely difficult to obtain from company archives. Distance downstream from compressor discharge is a valid surrogate for the missing information. The information provided by the JIP participants is best described as a series of individual datasets, as follows: (a) In-Service Ruptures and Leaks, Hydrostatic Tests Dataset 1 Consisted of around 135 records from in-service failures and hydrostatic test failures dating from the 1960s to 2005, on pipelines coated with coal tar. All the occurrences were recorded as high pH SCC. Dataset 2 Consisted of around 380 records from hydrostatic tests conducted between 1985 and 2005, on pipes that were predominantly coal tar coated. SCC failures occurred in about 4% of the hydrostatic tests; the rest were completed without SCC failures. All the SCC was recorded as high pH type.

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