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.

Steady State Performance Simulation of Natural Gas Pipeline Driven by Compressor Stations

2016 ◽  
Author(s):  
S. M. Suleiman ◽  
Y. G. Li
Keyword(s):  
Steady State ◽  
Natural Gas ◽  
Flow Rate ◽  
Operating Conditions ◽  
Simulation Approach ◽  
Gas Pipelines ◽  
Performance Simulation ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
Pumping Stations

Natural gas pipeline plays an important role in transporting natural gas over a long distance. Its performance and operating behavior are affected by many factors, such as ambient conditions, natural gas flow rate, operation and control of compressor pumping stations, etc. Better understanding of the performance and behavior of an integrated pipeline-compressor system used for gas transmission will be beneficial to both design and operation of natural gas pipelines. This paper introduces a novel steady-state thermodynamic performance simulation approach for natural gas pipelines based on fundamental thermodynamics with the inclusion of the coupling between a pipeline and compressor pumping stations. A pipeline resistance model, a compressor performance model characterized by an empirical compressor map and a pipeline control schedule for the operation of an integrated pipeline-compressor system are included in the simulation approach. The novel approach presented in this paper allows the analysis of the thermodynamic coupling between compressors and pipes and the off-design performance analysis of the integrated pipeline-compressor system. The introduced simulation approach has been applied to the performance simulation of a typical model pipeline driven by multiple centrifugal compressor pumping stations. It is assumed in the pipeline control schedule that the total pressure at the inlet of compressor stations is kept constant when pipeline operating condition changes. Such pipeline operating conditions include varying ambient temperature and varying natural gas volumetric flow rate. The performance behavior of the pipeline corresponding to the change of operating conditions has been successfully simulated. The introduced pipeline performance simulation approach is generic and can be applied to different pipeline-compressor systems.

Fitness-for-Service Assessment for Weldments of the Natural Gas Pipeline by Using Failure Assessment Diagram

2002 ◽  
Author(s):  
Jung-Suk Lee ◽  
Jang-Bog Ju ◽  
Jae-il Jang ◽  
Dongil Kwon ◽  
Woo-sik Kim
Keyword(s):  
Natural Gas ◽  
Fracture Mechanics ◽  
Gas Pipeline ◽  
Gas Pipelines ◽  
Service Workers ◽  
Natural Gas Pipelines ◽  
Field Service ◽  
Natural Gas Pipeline ◽  
Failure Assessment ◽  
User Friendly

There are buried natural gas pipelines of which total length amounts to about 2.1×106m in Korea, and it is very important issue to evaluate FFS (Fitness-for-service) when a crack-like flaw was found in operating pipelines. But, the research about this had not yet been performed in Korea. So, this study constructed a FFS code appropriate to Korean natural gas pipeline through comparing and analyzing API 579 and BS 7910 that are lately. In addition, we developed the user-friendly software based on FFS code, so that field service workers who have little idea about fracture mechanics can use easily. The best merit of this code is that it is possible to evaluate FFS for welding HAZ in Korea natural gas pipeline.

scholarly journals Risk Analysis on Leakage Failure of Natural Gas Pipelines by Fuzzy Bayesian Network with a Bow-Tie Model

2017 ◽  
Vol 2017 ◽  
pp. 1-11 ◽  
Author(s):  
Xian Shan ◽  
Kang Liu ◽  
Pei-Liang Sun
Keyword(s):  
Natural Gas ◽  
Risk Analysis ◽  
Bayesian Network ◽  
Gas Pipeline ◽  
Weak Links ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
Major Mode ◽  
Bow Tie

Pipeline is the major mode of natural gas transportation. Leakage of natural gas pipelines may cause explosions and fires, resulting in casualties, environmental damage, and material loss. Efficient risk analysis is of great significance for preventing and mitigating such potential accidents. The objective of this study is to present a practical risk assessment method based on Bow-tie model and Bayesian network for risk analysis of natural gas pipeline leakage. Firstly, identify the potential risk factors and consequences of the failure. Then construct the Bow-tie model, use the quantitative analysis of Bayesian network to find the weak links in the system, and make a prediction of the control measures to reduce the rate of the accident. In order to deal with the uncertainty existing in the determination of the probability of basic events, fuzzy logic method is used. Results of a case study show that the most likely causes of natural gas pipeline leakage occurrence are parties ignore signage, implicit signage, overload, and design defect of auxiliaries. Once the leakage occurs, it is most likely to result in fire and explosion. Corresponding measures taken on time will reduce the disaster degree of accidents to the least extent.

scholarly journals Detection of Natural Gas Leakages Using a Laser-Based Methane Sensor and UAV

2021 ◽  
Vol 13 (3) ◽  
pp. 510
Author(s):  
Sebastian Iwaszenko ◽  
Piotr Kalisz ◽  
Marcin Słota ◽  
Andrzej Rudzki
Keyword(s):  
Natural Gas ◽  
Field Experiments ◽  
Measurement Data ◽  
Gas Pipeline ◽  
Gas Pipelines ◽  
Spatially Correlated ◽  
Natural Gas Pipelines ◽  
Natural Gas Pipeline ◽  
Accuracy Of Measurements ◽  
Methane Concentrations

The safety of the gas transmission infrastructure is one of the main concerns for infrastructure operating companies. Common gas pipelines’ tightness control is tedious and time-consuming. The development of new methods is highly desirable. This paper focuses on the applications of air-borne methods for inspections of the natural gas pipelines. The main goal of this study is to test an unmanned aerial vehicle (UAV), equipped with a remote sensing methane detector, for natural gas leak detection from the pipeline network. Many studies of the use of the UAV with laser detectors have been presented in the literature. These studies include experiments mainly on the artificial methane sources simulating gas leaks. This study concerns the experiments on a real leakage of natural gas from a pipeline. The vehicle at first monitored the artificial source of methane to determine conditions for further experiments. Then the experiments on the selected section of the natural gas pipelines were conducted. The measurement data, along with spatial coordinates, were collected and analyzed using machine learning methods. The analysis enabled the identification of groups of spatially correlated regions which have increased methane concentrations. Investigations on the flight altitude influence on the accuracy of measurements were also carried out. A range of between 4 m and 15 m was depicted as optimal for data collection in the natural gas pipeline inspections. However, the results from the field experiments showed that areas with increased methane concentrations are significantly more difficult to identify, though they are still noticeable. The experiments also indicate that the lower altitudes of the UAV flights should be chosen. The results showed that UAV monitoring can be used as a tool for the preliminary selection of potentially untight gas pipeline sections.

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.

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.

scholarly journals Effects of hydrogen blending on hydraulic and thermal characteristics of natural gas pipeline and pipe network

2021 ◽  
Vol 76 ◽  
pp. 70
Author(s):  
Heng Zhang ◽  
Jingfa Li ◽  
Yue Su ◽  
Peng Wang ◽  
Bo Yu
Keyword(s):  
Natural Gas ◽  
Flow Rate ◽  
Centrifugal Compressor ◽  
Volume Flow Rate ◽  
Thermal Characteristics ◽  
Volume Flow ◽  
Gas Pipeline ◽  
Pipe Network ◽  
Joint Operation ◽  
Natural Gas Pipeline

Blending a fraction of hydrogen into the natural gas pipeline or urban pipe network is an efficient approach for hydrogen delivery. In this paper, the mathematical model of Hydrogen-Blended Natural Gas (HBNG) transportation is established, and the influences of hydrogen blending on hydraulic and thermal characteristics of natural gas pipeline and pipe network are numerically investigated. The impact of hydrogen blending ratio on the performance of centrifugal compressor and the operating point for joint operation of pipeline and compressor is discussed. Results illustrate that compared with natural gas without hydrogen, the hydrogen blending can reduce the pipeline friction resistance and increase the volume flow rate. However, due to the lower volumetric calorific value of HBNG, the energy flow rate actually decreases under the same transportation condition. Meanwhile, the temperature drop along the pipeline slows down due to the blended hydrogen. The performance degradation of centrifugal compressor occurs with the increasing hydrogen blending ratio, and the operating point for joint operation of pipeline and centrifugal compressor moves to the direction of higher volume flow rate and lower pressure. This study is expected to shed a light on the hydrogen delivery by natural gas pipelines and pipe networks.

scholarly journals Modified Leakage Rate Calculation Models of Natural Gas Pipelines

2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Qingmin Hou ◽  
Daheng Yang ◽  
Xiaoyan Li ◽  
Guanghua Xiao ◽  
Siu Chun Michael Ho
Keyword(s):  
Natural Gas ◽  
Flow Rate ◽  
Leakage Rate ◽  
Rate Change ◽  
Feedback Effect ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Pipe Model ◽  
Flow Rate Change ◽  
The Impact

The leakage rate is an essential parameter for the risk assessment and failure analysis of natural gas pipelines. The leakage rate of a natural gas pipeline should be calculated quickly and accurately to minimize consequences. First, in this study, models to estimate the leakage rate of natural gas pipelines are reclassified, and the theoretical range of application for each model is also analysed. Second, the impact of the leakage on the flow rate upstream of the leak point is considered, and the method of successive approximation is used to realize this feedback effect of flow rate change. Then, a modified hole-pipe model is developed to calculate the natural gas leakage rate in this paper. Compared with the leakage rate calculated by the hole-pipe model, the leakage rate calculated by the modified hole-pipe model is smaller and closer to the actual leakage rate due to the consideration of the feedback effect of the flow rate change. Finally, the leakage rate curves of the hole-pipe model and the modified hole-pipe model under different d/D conditions are obtained through simulation. The simulation results show that the modified hole-pipe model is able to calculate the leakage rate of any leak aperture, such as the hole-pipe model, and also at a higher accuracy level than the hole-pipe model.

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.

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