A Model for Sizing High Consequence Areas Associated With Natural Gas Pipelines

2002 ◽  
Author(s):  
Mark J. Stephens ◽  
Keith Leewis ◽  
Daron K. Moore
Keyword(s):  
Natural Gas ◽  
Release Rate ◽  
Gas Pipeline ◽  
Intensity Level ◽  
Operating Pressure ◽  
Worst Case ◽  
Damage Area ◽  
Natural Gas Pipelines ◽  
Failure Event ◽  
Extent Of Damage

The failure of a high-pressure natural gas pipeline can lead to various outcomes, some of which can pose a significant threat to people and property in the immediate vicinity of the failure location. The dominant hazard is thermal radiation from a sustained jet or trench fire. An estimate of the ground area affected by a credible worst-case failure event can be obtained from a model that characterizes the heat intensity associated with rupture failure of the pipe where the escaping gas is assumed to feed a sustained trench fire that ignites very soon after line failure. An equation has been developed that relates the diameter and operating pressure of a pipeline to the size of the area likely to experience high consequences in the event of an ignited rupture failure. The model upon which the hazard area equation is based consists of three parts: 1) a fire model that relates the rate of gas release to the heat intensity of the fire as a function of distance from the fire source; 2) an effective release rate model that provides a representative steady-state approximation to the actual transient release rate; and 3) a heat intensity threshold that establishes the sustained heat intensity level above which the effects on people and property are consistent with the adopted definition of a so-called High Consequence Area. The validity of the proposed model is established by a comparison between the predicted extent of the damage area and the actual extent of damage for significant gas pipeline failure incidents reported in the public domain.

Comparison of PIR to PIPESAFE-Based 1% Lethality Zones for Natural Gas Pipelines

2014 ◽  
Author(s):  
Aleksandar Tomic ◽  
Shahani Kariyawasam
Keyword(s):  
Natural Gas ◽  
Small Diameter ◽  
Gas Pipeline ◽  
Accurate Estimation ◽  
Simple Relationship ◽  
Gas Pipelines ◽  
Friction Forces ◽  
Natural Gas Pipelines ◽  
Decay Factor ◽  
Outflow Rate

A lethality zone due to an ignited natural gas release is often used to characterize the consequences of a pipeline rupture. A 1% lethality zone defines a zone where the lethality to a human is greater than or equal to 1%. The boundary of the zone is defined by the distance (from the point of rupture) at which the probability of lethality is 1%. Currently in the gas pipeline industry, the most detailed and validated method for calculating this zone is embodied in the PIPESAFE software. PIPESAFE is a software tool developed by a joint industry group for undertaking quantitative risk assessments of natural gas pipelines. PIPESAFE consequence models have been verified in laboratory experiments, full scale tests, and actual failures, and have been extensively used over the past 10–15 years for quantitative risk calculations. The primary advantage of using PIPESAFE is it allows for accurate estimation of the likelihood of lethality inside the impacted zone (i.e. receptors such as structures closer to the failure are subject to appropriately higher lethality percentages). Potential Impact Radius (PIR) is defined as the zone in which the extent of property damage and serious or fatal injury would be expected to be significant. It corresponds to the 1% lethality zone for a natural gas pipeline of a certain diameter and pressure when thermal radiation and exposure are taken into account. PIR is one of the two methods used to identify HCAs in US (49 CFR 192.903). Since PIR is a widely used parameter and given that it can be interpreted to delineate a 1% lethality zone, it is important to understand how PIR compares to the more accurate estimation of the lethality zones for different diameters and operating pressures. In previous internal studies, it was found that PIR, when compared to the more detailed measures of the 1% lethality zone, could be highly conservative. This conservatism could be beneficial from a safety perspective, however it is adding additional costs and reducing the efficiency of the integrity management process. Therefore, the goal of this study is to determine when PIR is overly conservative and to determine a way to address this conservatism. In order to assess its accuracy, PIR was compared to a more accurate measure of the 1% lethality zone, calculated by PIPESAFE, for a range of different operating pressures and line diameters. Upon comparison of the distances calculated through the application of PIR and PIPESAFE, it was observed that for large diameters pipelines the distances calculated by PIR are slightly conservative, and that this conservativeness increases exponentially for smaller diameter lines. The explanation for the conservatism of the PIR for small diameter pipelines is the higher wall friction forces per volume transported in smaller diameter lines. When these higher friction forces are not accounted for it leads to overestimation of the effective outflow rate (a product of the initial flow rate and the decay factor) which subsequently leads to the overestimation of the impact radius. Since the effective outflow rate is a function of both line pressure and diameter, a simple relationship is proposed to make the decay factor a function of these two variables to correct the excess conservatism for small diameter pipelines.

An Upheaval Buckling Limit State Function for Onshore Natural Gas Pipelines

2008 ◽  
Author(s):  
Ian Matheson ◽  
Wenxing Zhou ◽  
Joe Zhou ◽  
Rick Gailing
Keyword(s):  
Natural Gas ◽  
Elevated Temperatures ◽  
Limit State ◽  
State Function ◽  
Operating Pressure ◽  
Limit State Function ◽  
Gas Pipelines ◽  
Upheaval Buckling ◽  
Natural Gas Pipelines ◽  
Axial Forces

The reliability-based design and assessment (RBDA) methodology has gained increasing acceptance in the pipeline industry, largely due to a multi-year PRCI program aimed at establishing RBDA as a viable alternative for the design and assessment of onshore natural gas pipelines. A key limit state of buried pipelines that operate at elevated temperatures is upheaval buckling. The elevated temperatures generate large compressive axial forces that can cause Euler buckling susceptibility. The tendency to buckle is increased at vertical imperfections (i.e. a series of cold formed bends) that primarily occur due to topography. Upheaval buckling in itself is not an ultimate limit state but can lead to high strains, local buckling, high cycle fatigue, expensive remediation measures, and even loss of pressure integrity. The critical forces at which upheaval buckling occurs for typical hill-crest type imperfections present in onshore pipelines cannot be readily predicted using analytical methods. A parametric study is therefore undertaken using non-linear finite element analyses to generate a matrix of upheaval buckling responses. The critical force for the onset of upheaval buckling is then developed using a series of empirical relationships to capture the influences of all key parameters. An upheaval buckling limit state function is subsequently developed by comparing the critical buckling force with applied compressive force, which is a function of operating pressure and temperature differential between the operating and tie-in conditions. The limit state function can be readily implemented in a reliability analysis framework to calculate the pipeline failure probability due to upheaval buckling.

scholarly journals Options of Natural Gas Pipeline Reassignment for Hydrogen: Cost Assessment for a Germany Case Study

2019 ◽  
Author(s):  
Simonas Cerniauskas ◽  
Antonio Jose Chavez Junco ◽  
Thomas Grube ◽  
Martin Robinius ◽  
Detlef Stolten
Keyword(s):  
Natural Gas ◽  
Energy System ◽  
Gas Pipeline ◽  
Cost Functions ◽  
Pipeline System ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
System P ◽  
Availability Constraints ◽  
Hydrogen Supply

The uncertain role of the natural gas infrastructure in the decarbonized energy system and the limitations of hydrogen blending raise the question of whether natural gas pipelines can be economically utilized for the transport of hydrogen. To investigate this question, this study derives cost functions for the selected pipeline reassignment methods. By applying geospatial hydrogen supply chain modeling, the technical and economic potential of natural gas pipeline reassignment during a hydrogen market introduction is assessed.The results of this study show a technically viable potential of more than 80% of the analyzed representative German pipeline network. By comparing the derived pipeline cost functions it could be derived that pipeline reassignment can reduce the hydrogen transmission costs by more than 60%. Finally, a countrywide analysis of pipeline availability constraints for the year 2030 shows a cost reduction of the transmission system by 30% in comparison to a newly built hydrogen pipeline system.

High Energy Natural Gas Internal Corrosion Susceptibility Analysis

2014 ◽  
Author(s):  
David Owen ◽  
Simon Schapira
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Hydrogen Sulphide ◽  
Free Water ◽  
High Energy ◽  
Gas Pipeline ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Corrosion Susceptibility

Alliance Pipeline operates an integrated Canadian and U.S. high-pressure, rich natural gas transmission pipeline system. Rich natural gas pipelines are unique in that the product transported in these pipelines contains greater amounts of higher molecular weight hydrocarbons than would be transported in a dry natural gas pipeline. The specifications for gas quality however are very similar and require the product to contain less than sixty five mg/m3 water, no free liquids and/or objectionable materials such as bacteria, ashphaltene, gum, etc. The acid gases, carbon dioxide and hydrogen sulphide, are also required to be below certain values (see Table 1). Corrosion is not expected to occur under these conditions due to the lack of free water available for the development of an electrochemical corrosion cell. However, there are instances where the gas quality may vary and this gas enters facility piping for short periods of time. A method has been developed by Pipeline Research Council International (PRCI) to determine the internal corrosion susceptibility for dry gas natural gas pipelines but there are currently no industry accepted models which determine the internal corrosion susceptibility for high energy natural gas (HENG) pipeline systems. Accordingly, it is important for operators of pipelines with high energy natural gas (HENG) to collect and analyze these off specification events and develop a method to determine the relative impact on internal corrosion susceptibility. It is perhaps more important for operators to use this method to develop a strategy to prioritize facility piping for inspection and confirm the absence of internal corrosion. An Internal Corrosion Susceptibility Assessment (ICSA) method has been developed for HENG which considers off specification water, carbon dioxide, and hydrogen sulphide contents in the HENG. The analysis has been enhanced to also consider low temperature operation and hydrocarbon dew-point variations. The model has been effectively trialed over the last number of years to prioritize inspections and has been further tested against PRCI research and models developed for dry gas internal corrosion susceptibility. All internal corrosion models need to identify free water as prime contributor to susceptibility, thus the subject model is considered adaptable to other gas pipeline systems. This paper discusses the methods used to develop the model, the challenges encountered and results of the field inspections conducted.

The Reliability-Based Assessment of an In-Service X80 Natural Gas Pipeline in China

2014 ◽  
Author(s):  
Kai Wen ◽  
Jing Gong ◽  
Boyuan Zhao ◽  
Wenwei Zhang ◽  
Zhenyong Zhang
Keyword(s):  
Monte Carlo ◽  
Natural Gas ◽  
Reliability Analysis ◽  
Limit State ◽  
Gas Pipeline ◽  
Industrial Practice ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
State Models ◽  
Basic Input

Guidelines for the application of reliability-based design and assessment to natural gas pipelines were developed under PRCI sponsorship in 2005. The methodology underlying these guidelines has since been adopted as a non-mandatory Annex in the CSA Z662 standard (Annex O). Following the code in CSA Z662 Annex O, the reliability analysis of an in-service X80 pipeline in North-West China is performed using Monte Carlo technique. In this paper, the distributions of basic input parameters such as loadings, material property is derived based on the data collected from industrial practice. And the analysis of limit states, such as yielding of the defect-free pipeline, bursting of the defect-free pipeline, local buckling due to restrained thermal expansion and excessive plastic deformation, is proceeded based on these distributions. The core of reliability analysis lies in the selection and correction of limit state functions. The modification and extension of limit state models is very significant to accurately calculate probability of failure of different natural gas pipelines, so the limit state models are refined to adapt to the specific work conditions in China. A Monte Carlo reliability analysis framework capable of incorporating the data of industrial practice and limit state models has been developed and applied to the evaluation of the X80 natural gas pipeline, then a practical approximation is developed by using Monte Carlo simulation results. A practical example of an in-service X80 natural gas pipeline is presented to illustrate the availability of the reliability analysis. Furthermore, results generated by different basic input parameters in a limit state function are compared. The sensitivity analysis shows the degree of influence of various basic parameters.

Failure Analysis of an In-Service Natural Gas Pipeline

2012 ◽  
Author(s):  
Huai-xiang Cao ◽  
Xing-qi Qiu ◽  
Xiao-jing Yao ◽  
Ming-da Song
Keyword(s):  
Stress Concentration ◽  
Natural Gas ◽  
Mechanical Damage ◽  
Gas Pipeline ◽  
Localized Corrosion ◽  
Damage Area ◽  
Natural Gas Pipeline ◽  
Micro Cracks ◽  
Initiation And Propagation ◽  
Combined Action

A natural gas pipeline which had been serviced nearly 10 years burst and led to fire. Analysis on samples taken from the pipeline had been made, the mechanism of crack initiation and propagation was discussed, and the cause of burst and fire of the pipeline was put forward. The analysis results showed that, the pipeline had some grooves along the axial mechanical damages, which caused the stress concentration. Except that, the coating in the mechanical damage area was broken, this caused the failure of cathodic protection (CP). Under the combined action of the stress concentration and the corrosion environment of the soil, localized corrosion in the mechanical damage area was caused, where micro-cracks initiated. Furthermore, in the stage of cracks propagation, the stress corrosion cracking (SCC) occurred due to the corrosion environment of the soil. Finally, with the cracks expanded, connected and grew, the residual wall of the pipe was small, and the accident arose because of insufficient strength.

scholarly journals An Investigation into the Volumetric Flow Rate Requirement of Hydrogen Transportation in Existing Natural Gas Pipelines and Its Safety Implications

Gases ◽  
2021 ◽  
Vol 1 (4) ◽  
pp. 156-179
Author(s):  
Abubakar Jibrin Abbas ◽  
Hossein Hassani ◽  
Martin Burby ◽  
Idoko Job John
Keyword(s):  
Natural Gas ◽  
Flow Rate ◽  
Compressibility Factor ◽  
Volumetric Flow Rate ◽  
Gas Pipeline ◽  
Internal Erosion ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
Wide Range

As an alternative to the construction of new infrastructure, repurposing existing natural gas pipelines for hydrogen transportation has been identified as a low-cost strategy for substituting natural gas with hydrogen in the wake of the energy transition. In line with that, a 342 km, 36″ natural gas pipeline was used in this study to simulate some technical implications of delivering the same amount of energy with different blends of natural gas and hydrogen, and with 100% hydrogen. Preliminary findings from the study confirmed that a three-fold increase in volumetric flow rate would be required of hydrogen to deliver an equivalent amount of energy as natural gas. The effects of flowing hydrogen at this rate in an existing natural gas pipeline on two flow parameters (the compressibility factor and the velocity gradient) which are crucial to the safety of the pipeline were investigated. The compressibility factor behaviour revealed the presence of a wide range of values as the proportions of hydrogen and natural gas in the blends changed, signifying disparate flow behaviours and consequent varying flow challenges. The velocity profiles showed that hydrogen can be transported in natural gas pipelines via blending with natural gas by up to 40% of hydrogen in the blend without exceeding the erosional velocity limits of the pipeline. However, when the proportion of hydrogen reached 60%, the erosional velocity limit was reached at 290 km, so that beyond this distance, the pipeline would be subject to internal erosion. The use of compressor stations was shown to be effective in remedying this challenge. This study provides more insights into the volumetric and safety considerations of adopting existing natural gas pipelines for the transportation of hydrogen and blends of hydrogen and natural gas.

scholarly journals Simulation of Coupled Power and Gas Systems with Hydrogen-Enriched Natural Gas

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7680
Author(s):  
Yifei Lu ◽  
Thiemo Pesch ◽  
Andrea Benigni
Keyword(s):  
Natural Gas ◽  
Renewable Energy Sources ◽  
Simulation Method ◽  
Gas Pipeline ◽  
Electricity Sector ◽  
Electrical Network ◽  
Pipeline Network ◽  
Gas Network ◽  
Natural Gas Pipelines ◽  
The Impact

Due to the increasing share of renewable energy sources in the electrical network, the focus on decarbonization has extended into other energy sectors. The gas sector is of special interest because it can offer seasonal storage capacity and additional flexibility to the electricity sector. In this paper, we present a new simulation method designed for hydrogen-enriched natural gas network simulation. It can handle different gas compositions and is thus able to accurately analyze the impact of hydrogen injections into natural gas pipelines. After describing the newly defined simulation method, we demonstrate how the simulation tool can be used to analyze a hydrogen-enriched gas pipeline network. An exemplary co-simulation of coupled power and gas networks shows that hydrogen injections are severely constrained by the gas pipeline network, highlighting the importance and necessity of considering different gas compositions in the simulation.

scholarly journals Analysis of Stresses on Buried Natural Gas Pipeline Subjected to Ground Subsidence

1998 ◽  
Author(s):  
Hyoung-Sik Kim ◽  
Woo-Sik Kim ◽  
In-Wan Bang ◽  
Kyu Hwan Oh
Keyword(s):  
Natural Gas ◽  
Gas Pipeline ◽  
Ground Subsidence ◽  
Safety Criterion ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
Main Pipelines ◽  
Stress And Deformation ◽  
Buried Gas Pipeline ◽  
Allowable Settlement

This study was initiated to examine the stress and deformation characteristics of the pipelines which were subjected to various environmental conditions in order to confirm their integrity. As the part of them, this paper presents the analysis results for the effect of ground subsidence combined with main loads on buried natural gas pipelines. The ground subsidence which can occur for buried gas pipeline has been classified to the three cases. Finite element method was used to analyze the effect of ground subsidence on pipeline of 26 inch (0.660 m) and 30 inch (0.762 m) diameter used as high pressure (70 Kgf/cm2(686.4 Pascal)) main pipelines. This paper shows the result of stress analysis for the pipelines subjected to those three case ground subsidence. Comparing these results with safety criterion of KOGAS (0.9 σ y), maximum allowable settlement and loads have been calculated.

Extending the In-Line Inspection Interval for a Gas Pipeline Using Direct Assessment

2008 ◽  
Author(s):  
Marcus McCallum ◽  
Graham Ford ◽  
Andrew Francis
Keyword(s):  
Natural Gas ◽  
Structural Reliability ◽  
Probabilistic Approach ◽  
Gas Pipeline ◽  
Time Dependent ◽  
Time Interval ◽  
Operating Pressure ◽  
Direct Assessment ◽  
Ground Survey ◽  
External Corrosion

RWE npower own and operate a 12km long 8″ diameter natural gas pipeline that supplies natural gas from the National Transmission System (NTS) to a CHP unit. The pipeline has a nominal wall thickness of 6.35mm, is constructed from API 51 X42 grade steel and has a maximum operating pressure of 75barg. The pipeline was commissioned about 8 years ago and has been operating safely since that time. The pipeline was designed in accordance with BS 8010 Parts 1 and 2, with consideration given to the Institute of Gas Engineers Recommendations, IGE/TD/1, IGE/TD/9 and IGE/TD/12. One of the requirements of IGE/TD/1 is that the time interval between in-line inspections should not normally exceed 10 years. However, IGE/TD/1 Edition 4 allows the time interval to be exceeded if justification can be demonstrated using risk based techniques. For older pipelines it is often possible to determine the required time dependent failure probability based on the results of previous ILIs. This allows the time to next ILI to be determined. This time will depend on what has been found previously and values of other pipeline parameters. However, in the case of this pipeline there are no previous ILI data. In view of the above a probabilistic approach to External Corrosion Direct Assessment (ECDA) was adopted. The method makes use of the results from the above ground surveys rather than ILI data. However, in this instance, rather than being used to determine the time interval to the next above ground survey the method was used to determine the time interval to the next (first) ILI. The method is based on structural reliability analysis (SRA) which is used to determine the time dependent probability of failure based on available data. In view of the quantity and quality of the available above ground survey data it was possible to use the method to extend the time to the next ILL by several years.

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