Newcastle upon Tyne, United Kingdom
Newcastle upon Tyne, United Kingdom

Time filter

Source Type

Batte A.D.,Macaw Engineering | Fessler R.R.,BIZTEK Consulting Inc. | Marr J.E.,TransCanada | Rapp S.C.,Spectra Energy Transmission
PPIM 2012 - 24th Pipeline Pigging and Integrity Management Conference | Year: 2012

A discussion on the Joint Industry Project Phase II program covers integrity management practices and experience gained in the last 5 yr concerning the application of hydrostatic testing, excavations, and in-line inspection (ILI) for integrity management of SCC in gas transmission pipelines; protocol for obtaining data from post-ILI excavations; the equivalence of ILI and hydrostatic testing; and continuous improvement for integrity management. This is an abstract of a paper presented at the Pipeline Pigging & Integrity Management Conference (Houston, TX 2/8-9/2012).


Jackson N.,UK National Grid Corporation | Baldwin P.,Noble Denton | Andrews B.,MACAW Engineering
Institution of Chemical Engineers Symposium Series | Year: 2012

There has been significant investment in the UK in wind power over recent years with wind power currently making up to 2.2 percent of the UK's energy supply. The UK has a target of generating 15 percent of all electricity from renewable sources by 2020 (source: Renewable UK). A significant proportion of this wind power is being provided by onshore wind turbines. These wind turbines range from small domestic wind turbines up to large utility scale wind farms. Although relatively rare, a number of wind turbine failures have occurred over the past 30 years. The extent of these failures can vary from gearbox fires through to blade failures and catastrophic failures of the wind turbine mast. These larger scale wind turbine failures could have a significant impact on buried pipelines in the vicinity of the wind turbine. These buried pipelines include high pressure gas, gasoline and oil pipelines. The failure of these pipelines would lead to the release of flammable material with potential hazards to individuals and/or property in the vicinity of the pipeline. These failures can also lead to significant energy supply failures as a result of the consequential pipeline damage. This paper summarises the work that has been undertaken by the UK Onshore Pipeline Operators' Association (UKOPA) to specify an appropriate separation distance between wind turbines and buried energy infrastructure. This separation distance has been developed using a risk-based approach to ensure that the risk of pipeline failure is acceptably low. The study was based on data collected for wind turbines in the UK and used a methodology that has been developed in the Netherlands. The study has assessed all of the wind turbine failure modes that could be a potential threat to the integrity of a pipeline including: blade failure; fall of the nacelle or rotor and toppling of the mast. © 2012 IChernE.


Batte D.,Macaw Engineering | Fessler R.R.,BIZTEK Consulting Inc. | Hereth M.L.,PPIC | Marr J.,TransCanada | Rapp S.C.,Spectra Energy Transmission
PPIM 2013 - Proceedings of the 25th Pipeline Pigging and Integrity Management Conference | Year: 2013

During a recently-completed Joint Industry Project (JIP), eight major gas pipeline operators have collated and reviewed their experience with current-generation EMAT in-line inspection (ILI) for detection, sizing, and evaluation of SCC. Results were available from over 45 pipeline inspections totaling > 3000 mi, during which over 100 features were confirmed by excavation to be SCC that would probably have failed a hydrostatic test. The understanding developed during the course of the JIP (Phase II) identified the issues and uncertainties to be considered when considering the use of EMAT ILI in lieu of hydrostatic testing for SCC threat management. A discussion covers the reliability of hydrostatic testing; probability of detection using EMAT ILI; flaws discovered and flaws remaining after EMAT ILI; the accuracy of EMAT ILI flaw dimensions; predicted failure pressures and crack severity assessments; field experience with EMAT ILI and comparison with hydrostatic tests; and re-inspection intervals after EMAT ILI. The experiences of the JIP participants during almost 50 EMAT ILI inspections led to the conclusion that EMAT ILI can be used in lieu of hydrostatic testing for SCC threat management provided that steps are taken to ensure the issues and uncertainties are properly addressed during the ILI performance evaluation and crack severity assessment processes. This is an abstract of a paper presented at the Proceedings of the 25th Pipeline Pigging & Integrity Management Conference (Houston, TX 2/13-14/2013).


Andrews R.M.,MACAW Engineering | Hadden M.,UK National Grid Corporation | Casson P.,MACAW Engineering | Kashap T.,UK National Grid Corporation | Johnstone S.A.,UK National Grid Corporation
Proceedings of the Biennial International Pipeline Conference, IPC | Year: 2014

Methods for assessing volumetric corrosion in fittings such as bends or branch connections are not well developed, although limited guidance is given in some codes. For other components and cases where the corrosion profile is complex or there are large external loads, these methods cannot be applied. In addition, detailed analysis of the actual corrosion shape and the applied loads may demonstrate significant additional margins compared with the code method. To do this, the actual profile of the corroded shape is required. This paper reports an initial study investigating methods of non-contact scanning a corroded fitting, constructing a finite element (FE) model of the corroded shape and prediction of the failure pressure. Two corroded welded branch connections which had been removed from a block valve installation were used. The surface profiles were measured using a laser scanner and the scans imported into a FE model generation system and detailed models of the damaged connections then developed. Non-linear analyses were carried out to predict the failure pressure using assumed and measured stress-strain curves. Failure was predicted to occur in the area of the weld between the forged connection and the header. Hydrostatic burst tests were carried out on the connections. In both tests failure initiated in the header pipe remote from the branch and the corroded area, and as a result the failure pressures were below those predicted by the FEA. However, the failures did occur at pressures about 20% higher than the original hydrostatic test pressure. Strain gauge data from the pressure tests were in reasonable agreement with the numerical predictions. Large strains were predicted and measured in the large artificial defect introduced in the second test. This program has demonstrated the feasibility of making detailed surface profile measurements of corroded components on site, and then using these profiles in a non-linear FEA to predict failure pressures. The development work needed for routine application is discussed, and the selection of a failure criterion for the FEA when analysing complex geometries where there may be substantial through wall bending is also considered. Copyright © 2014 by ASME.


Batte A.D.,Macaw Engineering | Fessler R.R.,BIZTEK Consulting Inc. | Marr J.E.,TransCanada | Rapp S.C.,Spectra Energy Transmission
Proceedings of the Biennial International Pipeline Conference, IPC | Year: 2012

A group of eight gas transmission pipeline operators, responsible collectively for operating over 160,000 miles of pipelines in North America, has participated in a Joint Industry Project (JIP) to examine the current status of Stress Corrosion Cracking (SCC) Threat Management. Many of these operators had previously participated in a JIP addressing the Integrity Management of SCC in High Consequence Areas. Completed in 2006, the JIP developed experience-based guidance for the conduct of hydrostatic testing and excavations, for the assessment of the severity of discovered defects, and for establishing the interval before the next assessment. The outcome was published in ASME STP-PT-011, and formed the basis for proposed revisions to ASME B31.8S. In this second phase of the work, the operational experiences and threat management experiences during the five years since 2006 have been reviewed. From an operational viewpoint, the situation has been very satisfactory; only three in-service failures (ruptures or leaks) due to SCC have been experienced during this period, a considerable reduction compared to the preceding years. However, there is still a legacy of SCC to be managed in older pipelines; for example, 80 near-critical cracks have been removed by hydrostatic testing, and around 100 cracks that would probably have failed a hydrostatic test have been discovered by crack detection ILI. From the threat management viewpoint, a consistent overall framework for addressing SCC is beginning to be established, within which the wide range of operational experience can be addressed using mitigation strategies that are appropriate, proportionate, and timely. Most operators, particularly those with a legacy of SCC in older pipelines, make use of hydrostatic testing. Several now make use of SCC Direct Assessment, following its acceptance as a formal process in around 2005, but mostly for addressing segments with low relative risk of SCC and/or no history of SCC. Many are exploring the application of crack detection ILI; among the JIP members around 45 runs totalling nearly 3000 miles have been completed using EMAT ILI vehicles, and more are scheduled. Almost all the JIP members are using two or more of these approaches in combination as part of their SCC Threat Management strategies. There are areas where the experiences of SCC Threat Management over the last five years point to opportunities for improvement. For SCC Direct Assessment, the use of feedback from excavations to refine the relative rankings for segment prioritisation and dig site selection will become an increasingly important aspect of process improvement. For crack detection ILI, the main issues are the accuracy and reliability of information determining the flaw size and shape for use in predictions of failure pressure and assessments of defect severity. As Threat Management moves from baseline assessment to regular re-assessment, issues that arise include determination of the re-assessment interval, particularly when using SCC Direct Assessment and crack detection ILI. There is also an issue about how best to actively monitor those segments where there is low relative risk and no experience of SCC. Copyright © 2012 by ASME.


Andrews R.M.,MACAW Engineering | Denys R.M.,Ghent University | Knauf G.,Salzgitter Mannesmann Forschung GmbH | Zarea M.,GDF SUEZ
Journal of Pipeline Engineering | Year: 2015

THE 1996 EDITION of the EPRG guidelines on the assessment of defects in transmission pipeline girth welds has been reviewed to extend their range of application.The revised 2014 guidelines replace and retain the three-tier structure of the old guidelines.The 2014 guidelines can be used for pipe grades up to X-80 and defect heights greater than 3 mm. A novel defect interaction criterion is given for co-planar defects in girth welds which comply with the EPRG material and performance requirements.Additionally, guidance on the pipe material and weld-metal testing requirements is given.The new guidelines provide conservative allowable defect sizes as they are fully validated by curved-wide-plate (CWP) test data. The guidelines are simple, transparent, and can be applied by users without requiring extensive experience in fracture mechanics.


Andrews R.M.,MACAW Engineering | Millwood N.,5G Orbital | Tiku S.,BMT Fleet Technology | Pussegoda N.,BMT Fleet Technology | And 2 more authors.
Proceedings of the Biennial International Pipeline Conference, IPC | Year: 2012

As part of a safety case for a subsea 13Cr pipeline, the operator wished to demonstrate that if a circumferential through wall crack developed, the crack would remain stable as a leak rather than growing to a full bore rupture. An initial fracture mechanics analysis had suggested that the margins on crack length were too small to make such a "leak before break" argument. This paper reports an integrated programme of small scale testing, numerical modelling and full scale testing which showed that a leak before break case could be made. 13Cr martensitic steel generally shows excellent toughness at the service temperature, as does the super duplex weld metal that was used for the girth welds. However, as the pipeline had been installed by reeling, there was some concern that the toughness may have been reduced. Hence a programme of fracture toughness testing was designed to generate tearing resistance curves for both as-received and pre-strained parent material and weld metal. Deep and shallow through thickness notched specimen geometries were tested to explore the effect of constraint on the toughness. Finite element analysis was used to predict the stress intensity for a range of crack lengths, including the effects of misalignment. Non-linear analyses were used to estimate the limit load for the cracked pipe. The test results were used as input to tearing analyses to Level 3 of BS 7910. These showed that the tolerable length of a through wall crack exceeded the length of anticipated defects by a factor of at least two. To confirm the fracture mechanics predictions, two full scale tests were carried out. These used pressure cycling to grow a through wall crack by fatigue. These cracks were stable under an internal pressure equal to the pipeline design pressure. The cracked specimens were then axially loaded to failure. Extensive tearing occurred before final failure at loads above those predicted by the fracture analysis, confirming the conservatism of the predictions. Copyright © 2012 by ASME.


Sandana D.,MACAW Engineering | Dale M.,MACAW Engineering | Charles E.A.,Northumbria University | Race J.,Northumbria University
Journal of Pipeline Engineering | Year: 2013

Transporting anthropogenic C02 in pipelines, either in dense phase or gaseous phase, is an essential component in the practical realisation of carbon capture and storage (CCS).Whichever phase is considered,the likelihood and severity of internal degradation mechanisms arising from C02 transportation under normal operating conditions and under process upsets needs to be assessed. Whilst internal corrosion has been a focus of research in this area, the risk of stress-corrosion cracking (SCC) has not been extensively investigated.This paper explores the level of risk posed by SCC in C02 pipelines, and the gaps in current knowledge, together with a presentation of test results that investigate the presence of SCC in simulated C02 environments in the presence of impurities.


Sandana D.,MACAW Engineering | Charles E.A.,Northumbria University | Dale M.,MACAW Engineering | Race J.,MACAW Engineering
NACE - International Corrosion Conference Series | Year: 2013

Transporting anthropogenic CO2 in pipelines is an essential component in the realisation and implementation of Carbon Capture and Storage (CCS). Transportation of dense CO2 has generally been the preferred economic solution, but projects in the United Kingdom (UK) have also considered transportation of gaseous CO2. Whichever option is selected, provision may need to be made to mitigate or prevent internal corrosion risks. This will require identifying and defining in the CO2 specification the maximum levels of water and impurities, e.g. nitrogen oxides (NOx) and sulphur oxides (SOx), such that internal corrosion risks are maintained at an acceptable level throughout the proposed service life of a pipeline. Equally, should there be a process upset in the CO2 stream conditioning procedure (e.g. failure of dehydration unit), then potential internal corrosion risks will need to be clearly defined in order to establish an effective mitigation strategy that maintains pipeline integrity. So far, while the corrosion research in this domain has focused on identifying plausible corrosion rates which may occur in these environments, the risk of Stress Corrosion Cracking (SCC) has not been extensively investigated. This paper explores whether SCC is possible in CO2 transporting pipelines. Gaps in current knowledge will be high-lighted. In addition some preliminary test results that indicate presence of SCC in simulated CO2 environments will be presented.


Sandana D.,MACAW Engineering | Dale M.,MACAW Engineering | Charles E.A.,Northumbria University | Race J.,Northumbria University
NACE - International Corrosion Conference Series | Year: 2013

Transporting anthropogenic CO2 in pipelines is an essential component in the realisation and implementation of Carbon Capture and Storage (CCS). Transportation of dense CO2 has generally been the preferred economic solution, but projects in the United Kingdom (UK) have also considered transportation of gaseous CO2. Whichever option is selected, provision may need to be made to mitigate or prevent internal corrosion risks. This will require identifying and defining in the CO2 specification the maximum levels of water and impurities, e.g. nitrogen oxides (NO X) and sulphur oxides (SOX), such that internal corrosion risks are maintained at an acceptable level throughout the proposed service life of a pipeline. Equally, should there be a process upset in the CO2 stream conditioning procedure (e.g. failure of dehydration unit), then potential internal corrosion risks will need to be clearly defined in order to establish an effective mitigation strategy that maintains pipeline integrity. So far, while the corrosion research in this domain has focused on identifying plausible corrosion rates which may occur in these environments, the risk of Stress Corrosion Cracking (SCC) has not been extensively investigated. This paper explores whether SCC is possible in CO2 transporting pipelines. Gaps in current knowledge will be high-lighted. In addition some preliminary test results that indicate presence of SCC in simulated CO2 environments will be presented. © 2013 by NACE International.

Loading Macaw Engineering collaborators
Loading Macaw Engineering collaborators