Risk Management最新文献

{"title":"Performance of Five Different Natural Gas and Hydrogen Blending Mixer Designs via CFD","authors":"K. Botros, Mohammad H. Shariati, Swaran Sandhawalia","doi":"10.1115/ipc2022-86895","DOIUrl":"https://doi.org/10.1115/ipc2022-86895","url":null,"abstract":"\u0000 The aspiration for blending hydrogen (H2) into natural gas (NG) in gas transmission systems is high and is happening globally. However, the mechanics and details of blending the two streams are not well developed or perfected. There is a need to arrive at the best technique and approach to achieve perfect blending to minimize the potential adverse impact on the operation of downstream facilities as well as on the end-users. The challenge is primarily driven by the fact that NG and H2 have vastly different properties, principally densities, that may lead to possible stratification, short circuiting, and pockets of undesirable high concentration of H2 in the blended stream. The paper documents Computational Fluid Dynamics (CFD) simulation results conducted on five different concepts of mixer/blending designs. These mixer designs are: i) single or multiple side entries, ii) dual spiral ribbon (DSR) type mixer, iii) venturi mixer, iv) hybrid mixer of DSR inside a venturi, and v) NC5 perforated tube bundle type mixer. An example of an NPS 12 (DN300) ultrasonic meter run with an NPS 20 (DN500) header was assumed throughout the analysis. It was found that the venturi mixing concept with a single side entry is the optimum design due to its simplicity, cost effectiveness, and relatively low pressure drop. With this simple design, 99% mixing efficiency is achieved within 13D at maximum flow, where D is the main header diameter downstream of the mixing station. The pressure drop coefficient for this design is estimated to be approx. 3.1, which amounts to ∼6 kPa at maximum flow, which is relatively low. However, mixing will halt at coefficient of variance = 0.2 (80% mixing efficiency) at very low flow rate of a turndown ratio of 20:1. Final selection of a mixer design from the five designs investigated depends on the tradeoff between mixing efficiency, pressure drop and cost.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"415 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84899278","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effects of Hydrogen Embrittlement on the Fracture Toughness of High-Strength Steel Structures","authors":"S. Agbo, Farhad Davaripour, K. Roy","doi":"10.1115/ipc2022-87174","DOIUrl":"https://doi.org/10.1115/ipc2022-87174","url":null,"abstract":"\u0000 Blending hydrogen into existing natural gas pipelines is being pursued as a means of delivering hydrogen to markets. However, as stated in ASME B31.12, high-strength steel pipelines under stress can be susceptible to hydrogen embrittlement, which is a phenomenon that could induce brittle fracture in steel. This study proposes a numerical framework using phase-field fracture modelling techniques to model the hydrogen embrittlement phenomenon in high-strength steels. The proposed numerical framework is validated against a Compact Tension experimental test specimen, which is deemed suitable to capture the crack-tip constraint observed in high strength steel. The finite element results show a good agreement with experimental results, which demonstrate the capability of the phase-field fracture model in reasonably predicting hydrogen embrittlement in high-strength steel. As such, the proposed numerical modelling framework could also be applicable to typical high strength steel pipelines.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73659713","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Susceptibility of a Virtual Pipeline Network to Fatigue and Cracking Threats in Hydrogen Service","authors":"Ollie Burkinshaw, Daniel Sandana, N. Gallon, A. Bhatia","doi":"10.1115/ipc2022-87089","DOIUrl":"https://doi.org/10.1115/ipc2022-87089","url":null,"abstract":"\u0000 Over the coming decade many projects will be initiated to convert existing natural gas pipelines to hydrogen service, often with ambitious schedules. However, there is currently little experience globally in successfully converting pipelines to hydrogen service and operating them safely. In North America, the gas transmission infrastructure represents construction from the 1920s up to the present day. This infrastructure contains a wide spectrum of different pipeline materials with large variations in properties, and an array of different resident and time-dependent integrity threats.\u0000 Prior to embarking on changes to hydrogen service, it is imperative to understand and mitigate the effects associated with the change in risk profile, driven by the known effects of hydrogen gas on the toughness and fatigue resistance of steel pipelines. These effects are complicated by the significant variation and uncertainty in the extent to which different pipeline materials will be affected.\u0000 Many papers and industry projects have examined the effects of hydrogen on material properties. However, few have assessed the scale of the challenge posed to safe operation and integrity management involved with repurposing an entire infrastructure. This paper uses a novel approach to explore how the current natural gas transmission network might stand up to a hypothetical switch to 100% hydrogen.\u0000 Available data gathered through inspections of gas transmission pipelines in North America will be utilised to create a virtual pipeline network. This virtual system is built from a range of different pipeline sizes, attributes and material properties to most closely represent a ‘typical’ proportion of the gas transmission network in North America. An array of cracks and crack-like integrity threats with sizes and morphologies that reflect typical frequencies and severities observed from real projects will be introduced into this virtual network.\u0000 This virtual network is a construct that allows the impact of hydrogen conversion on integrity management to be explored in a way that is representative of what a gas transmission pipeline operator may expect to encounter across a range of assets. The impacts will be explored through different scenarios, representing different extents of reductions in toughness and increases in fatigue crack growth rates, based on available material test data. This approach will provide an indication of the number of features that may be currently stable in natural gas but that may fail in hydrogen service. This hypothetical exercise will draw insights into the practicalities of safe operation of pipelines being contemplated for hydrogen service and the scale of the task that would be necessary to navigate this transition.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79549948","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Internal Corrosion Considerations for Hydrogen Embrittlement Inhibitors","authors":"S. P. Kotu, Christopher Kagarise, C. Taylor, S. Finneran","doi":"10.1115/ipc2022-87335","DOIUrl":"https://doi.org/10.1115/ipc2022-87335","url":null,"abstract":"\u0000 Converting natural gas pipelines to transport pure hydrogen or blends with natural is currently being implemented as part of the energy transition strategy to achieve net zero emissions. Addition of hydrogen to existing natural gas pipelines increases the risk of hydrogen embrittlement and poses potential integrity issues such as cracking to the pipelines. Prior work has demonstrated that the use of inhibitors such as oxygen, carbon monoxide, and others can inhibit a material’s adsorption of atomic hydrogen and have been proposed to reduce the risk of hydrogen embrittlement. While these inhibitors may potentially reduce the risk of hydrogen embrittlement, there may be unintended consequences if the impact of these inhibitors on internal corrosion is not carefully evaluated. For example, the use of oxygen in the inhibitors can increase the potential for oxygen corrosion. This paper covers the methodology to evaluate the impact of internal corrosion on pipelines for any inhibitors used to prevent hydrogen embrittlement before they are applied. The recommendations for internal corrosion control when using oxygen-based inhibitors are discussed. Additionally, a comprehensive review of the proposed inhibitors for hydrogen embrittlement along with a discussion on their mode of action to prevent or mitigate hydrogen embrittlement is presented.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75025365","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of Strain Based Assessment in Support of Operational and Mitigation Decisions","authors":"Banglin Liu, Yong-Yi Wang, Xiaotong Chen","doi":"10.1115/ipc2022-87337","DOIUrl":"https://doi.org/10.1115/ipc2022-87337","url":null,"abstract":"\u0000 A confirmed pipeline displacement due to ground movements often requires operational decisions regarding flow restriction and/or field mitigation. Some of the more frequently employed techniques for assessing the magnitude of the applied strain (strain demand), such as in-line inertial measurement unit (ILI IMU) or pipe-soil interaction analysis, may not be able to accommodate the timeframe for such decisions. The resulting lack of quantified strain demand and strain demand limit can potentially cause prolonged service interruptions or unnecessary field work under unfavorable access conditions.\u0000 A multi-leveled strain-based assessment (SBA) process is presented that was designed to support operational and mitigative decisions after confirmed pipe displacements. At the lower level, the methodology utilizes pipe locator data in conjunction with generalized pipe displacement profiles for quick determination of strain demands. At the higher level, conventional pipe-soil interaction analysis is used to refine the strain demand estimate as additional site data become available. The tensile strain capacity (TSC) is determined using one of three available options based on data availability. Integrity assessments can then be performed for both the current operating condition and future scenarios. For sites deemed safe at the moment of assessment, allowable movements at a future point can be established based on the margins between the strain demand and strain capacity. The allowable movements can be used in conjunction with geotechnical assessment to establish re-assessment intervals and trigger further field verification or mitigation activities.\u0000 An example SBA of a landslide in the Appalachian region is presented to illustrate the applications of the multi-leveled process with key considerations and some practical constraints in mind. Two gas transmission pipelines in a shared right of way were displaced after a slope movement. Pipeline A was shut-in immediately due to a larger displacement while Pipeline B remained in operation pending an integrity assessment. An initial lower-level SBA indicated neither pipeline had a sufficient margin between the strain capacity and the strain demand. Pipeline B was shut-in as a result. The initial assessment also pointed to different directions for refined assessments. Pipeline A, with the higher TSC and demand estimates, was subject to a refined pipe-soil interaction analysis to reduce the potential over-estimation of the strain demand. Pipeline B, with the lower TSC and demand estimates, was subject to in-ditch NDE in a controlled excavation, so that the TSC estimate can be updated with accurate weld-specific flaw information. The refined assessment indicated sufficient margins of safety for both pipelines. Consequently, both lines were returned to service, and a slide repair was implemented.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72806632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reliability Assessment of Pipeline Third Party Damage","authors":"Mahsa Mehranfar, M. Sen, Christopher Lam, S. Bott","doi":"10.1115/ipc2022-87232","DOIUrl":"https://doi.org/10.1115/ipc2022-87232","url":null,"abstract":"\u0000 Pipeline failure statistics indicate that mechanical damage caused by third-party excavation represents the largest threat to the integrity of onshore oil and gas pipelines in North America. In 1999, PRCI developed a reliability model that quantifies the pipeline probability of failure due to the 3rd party damage threat. The model employs a fault tree approach comprised of four main elements: the probability of excavation occurring on the pipeline alignment, the effectiveness of damage preventive measures, the probability that the excavation depth exceeds the depth of cover, and the probability that the excavator force is sufficient to fully penetrate the pipe wall. The PRCI model has been implemented by numerous operating companies over the past two decades.\u0000 Despite this large contribution, there has been a gap in quantitative assessment techniques regarding the effectiveness of the methods used to prevent mechanical damage, and the pipelines resistance to the impact loads applied to pipelines by excavation equipment. In 2020 Enbridge applied this model to its 25,000+ km liquid pipeline system. During implementation numerous learnings and areas for improvement were identified. Correspondingly, the model was expanded to improve consideration of four important 3rd party damage threats that are not currently included within the model: agricultural activity, vehicle crossings, pipeline exposures, and mitigation activities. The results of this updated model showed that the probability of failure’s due to 3rd party damage were generally increased at locations with high population density, agricultural land use, and road crossings, that exhibited shallow cover. It is expected that this updated model will assist in prioritizing the mitigation of various locations that are potentially susceptible to the 3rd party damage threat in alignment with operator expectations. This paper discusses the data gathering steps required for implementation, example probability of failure results, and provides the details of the model updates which may be incorporated by other operators.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80715214","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An Integrated Model for Predicting Stress Corrosion Cracking of Buried Pipelines","authors":"Guanlan Liu, Francois Ayello, G. Vervake, J. Beck, Ramgopal Thodla, N. Sridhar","doi":"10.1115/ipc2022-87136","DOIUrl":"https://doi.org/10.1115/ipc2022-87136","url":null,"abstract":"\u0000 Stress corrosion cracking (SCC) is a type of crack that grows in a corrosive environment, which threatens the integrity of pipeline and may lead to major and/or sudden pipeline failures. The complex mechanism of SCC involves interactions of electrolyte chemistry, coating quality, metallurgy, stress, and other pipeline operating conditions. As a result, it is challenging to estimate the SCC failure probability at a certain location of the pipeline. Additionally, the nature of data uncertainty in the pipeline operation made a precise SCC prediction even more difficult. In this study, a Bayesian network model was developed to integrate the theoretical and empirical knowledge regarding SCC prediction. By combining the relevant parameters and varying mechanisms, both high pH SCC and near-neutral pH SCC probabilities and crack growth rate can be predicted. The initial prediction results are validated by comparing with the field SCC data. The Bayesian network SCC model can serve as a reference tool for the pipeline operators to determine the time or location of SCC inspection, repair, or replacement. The probabilistic results make it feasible to run sensitivity analysis, to determine the impact of uncertainty data.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82118547","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Prioritizing Retrofits of Non-Piggable Transmission Pipelines Using an Internal Corrosion Structural Reliability Model","authors":"Gabriel Langlois-Rahme, Daryl Bandstra, V. Iacobellis, M. Safari","doi":"10.1115/ipc2022-87273","DOIUrl":"https://doi.org/10.1115/ipc2022-87273","url":null,"abstract":"\u0000 Internal Corrosion (IC) is a time dependent threat to pipelines that leads to wall loss due to a reaction between pipe material and the products or contaminants being transported. Certain vintage pipelines are not piggable, meaning that Inline Inspection measurement tools cannot be used to measure IC defects. Furthermore, being older, these pipelines are more susceptible to time dependent threats such as IC due to their longer exposure time. Operators often need to prioritize retrofits between different non-piggable pipelines, and the approach described in this study uses a structural reliability approach to estimate the expected frequency of failure for non-piggable pipeline segments and ranks them accordingly.\u0000 This model captures the range of potential IC defect severity by using in-line inspection data from different pipeline asset types (e.g., Well Laterals, Transmission) to build empirical distributions of defect length and depth corrosion growth rate (CGR). These asset types serve as an indirect measure of gas quality as evidenced by differences in the defect distributions and anomaly densities. By characterizing CGR as a distribution for different asset types and using the industry standard Growth-by-Rule method to model defect depth, the model considers both asset type and pipe age when predicting the defect depth distribution in the current year. This projected depth distribution is used with physical and operating parameters (e.g., diameter, WT, pressure) in a structural reliability model to estimate the probability of failure for the segment under consideration.\u0000 The structural reliability-based prioritization approach described in this paper provides a methodology to utilize physical and operating parameters of an un-piggable pipeline together with information from inspected pipelines to rank the expected severity of a given un-piggable line. These segment ranks were finally compared to ranks generated using other heuristic methods to quantify the benefits of this more detailed analysis methodology.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83686156","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Develop Standard Testing Approach for Evaluation of Materials Compatibility in Hydrogen Service","authors":"Ashwini Chandra, TJ Prewitt, S. Finneran","doi":"10.1115/ipc2022-87359","DOIUrl":"https://doi.org/10.1115/ipc2022-87359","url":null,"abstract":"\u0000 Transformation and decarbonization of existing energy systems are a key part of global energy transition efforts to meet targets set in the COP21 Paris Agreement. In effort to reduce greenhouse gas emissions and decarbonize the existing energy systems, hydrogen has emerged as an attractive fuel option for energy storage and transportation. One key aspect considered is the potential for blending and transporting hydrogen in existing natural gas pipelines. It is recognized that the introduction of hydrogen in existing carbon steel pipelines may present a myriad of effects including hydrogen embrittlement, increases to fatigue crack growth rate, and reductions in ductility and yield strength when exposed to susceptible steels under stress. These potential effects may vary based on the vintage, strength of steel, weld type, and other specific pipeline characteristics, therefore the specific threats and severity of each should be evaluated for numerous pipeline configurations.\u0000 Establishing a standard and consistent approach for evaluation compatibility of pipeline materials with hydrogen service would be beneficial to the industry. The existing practice of assessing defects in hydrogen service is based on guidance from ASME B31.12. However, the guidance provided in ASME B31.12 is based on the response of hydrogen at higher concentrations and pressures than will be expected in typical transmission or distribution pipeline systems.\u0000 This paper provides a recommended approach to performing testing and analysis for existing and new pipe steels under various hydrogen blends. This would provide a framework across the industry for which a consistent approach for assessing compatibility could be assessed, and allow for improved alignment and compilation of material test data to establish a broader understanding of material compatibility.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76682557","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Consequence Modeling of Hypothetical Releases From Carbon Dioxide (CO2) Transport Pipelines","authors":"Jeremy Fontenault, Tara Franey","doi":"10.1115/ipc2022-87131","DOIUrl":"https://doi.org/10.1115/ipc2022-87131","url":null,"abstract":"\u0000 Reducing carbon emissions is increasingly becoming a priority to combat climate change. Carbon capture, utilization, and storage (CCUS) is one of the primary approaches to help combat carbon emissions in the oil and gas and other industries. These technologies involve capturing the CO2 from combustion, refining, or other types of industrial activities, then transporting that CO2 to another location where it can be utilized or stored underground or below the sea floor. Pipelines are one of the primary transportation methods, and as more CCUS operations start to come online, more pipelines will be built or converted from transporting hydrocarbons to transporting CO2.\u0000 Like most products transported by pipeline, there are risks associated with CO2 transport. However, these risks are quite different from those of hydrocarbon transport. CO2 is not flammable and is less toxic. The primary risk associated with a release of a large quantity of CO2 is the displacement of oxygen that can cause an asphyxiation hazard. Direct exposure to cooled CO2 liquid or gas can cause irritation or even frostbite. CO2 releases into water can harmfully alter the water pH level. Due to these risks, it is necessary for operators to understand the potential consequences of an accidental loss of containment.\u0000 This paper will review an approach for consequence modeling used for the potential conversion of service from crude oil transport to CO2, for a confidential pipeline operator. This will include an overview of the modeling tools used, the inputs and assumptions incorporated, the range of hypothetical release scenarios considered (including full-bore ruptures and smaller leaks) and overview of the results. This assessment was used to answer a variety of questions asked to evaluate whether this conversion was a viable project. This included determining the potential impact area from a worst-case discharge, what receptors are at risk, and identifying optimal operational considerations (i.e. valve type and placement, leak detection requirements, etc.).\u0000 This approach for consequence modeling for CO2 pipelines can be used to help ensure safety during the coming energy transition.","PeriodicalId":21327,"journal":{"name":"Risk Management","volume":"121 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88111172","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}