Analysis of Two-Phase Stratified Flow and Liquid Hold Up at Dead Ends of T-Sectioned Natural Gas Pipelines

2015 ◽  
Author(s):  
Kaushik Das ◽  
Debashis Basu ◽  
Xihua He ◽  
Stuart Stothoff ◽  
Kevin Supak ◽  
...  
Keyword(s):  
Natural Gas ◽  
Flow Rate ◽  
Liquid Water ◽  
Liquid Velocity ◽  
Analytical Data ◽  
Operating Conditions ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Superficial Liquid Velocity

T-sectioned configurations with a deadleg at the stopple are present in natural gas pipelines, where liquid water may accumulate, increasing the potential for internal corrosion. The objectives of the present study are to explore the pipeline operating conditions under which water enters the deadleg and define an operating protocol to prevent water accumulation in deadlegs. A combined computational fluid dynamics (CFD) experimental and analytical study was conducted to understand the behavior of liquid slugs at the T-junctions with dead ends. The flow equations were solved as an unsteady multiphase (gas and water) incompressible flow problem using the Volume of Fluid (VoF) Method. The analytical calculations were based on a modified form of the macroscopic mechanical energy balance equation. In order to computationally simulate the critical velocity at which water enters the deadleg, the inlet gas flow rate was specified to be a fixed value, while the water flow rate was gradually increased. The liquid entirely bypasses the deadleg until the liquid water velocity exceeds a critical value, which was noted as the critical superficial liquid velocity. The experimental study was conducted using a flow loop to understand the behavior of liquid water at the T-junction and determine the condition when liquid enters the deadleg. The analytical and computed solutions were compared with experimental observations. The computed results follow the same pattern as the experimental and analytical data. Solutions indicate that critical superficial liquid velocity is linearly dependent on superficial inlet gas velocity.

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.

scholarly journals Membrane-Based Electrochemical Sensors for Detecting Internal Corrosion Risk of Natural Gas Pipelines

2020 ◽  
Vol MA2020-01 (28) ◽  
pp. 2140-2140
Author(s):  
Margaret Ziomek-Moroz ◽  
Timothy Duffy ◽  
Derek M. Hall ◽  
Serguei N. Lvov
Keyword(s):  
Natural Gas ◽  
Electrochemical Sensors ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Corrosion Risk

A Probabilistic Model for Predicting Internal Corrosion Threat in Dry Natural Gas Pipelines

2010 ◽  
Author(s):  
Fengmei Song ◽  
John McFarland ◽  
Barron Bichon ◽  
Luc Huyse ◽  
Fraser King ◽  
...  
Keyword(s):  
Natural Gas ◽  
Probabilistic Model ◽  
Operating Temperature ◽  
Gas Pipelines ◽  
Consensus Definition ◽  
Pipe Surface ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Water Condensation ◽  
Temperature And Pressure

A probabilistic model is developed in this work to predict the internal corrosion (IC) threat due to water condensation in dry natural gas pipelines. The model involves the understanding of tariff limits (TLs) for water and other corrosive species in natural gas; a consensus definition of an extremely unlikely condition for IC threat; a statistical analysis of field operating temperature, pressure, and water content (WC) data from a number of operators; and a known but modified relation of the saturated WC vs. operating temperature and pressure. By setting the limit of the probability of water condensation at 2% of the time that the pipe surface is wet, the maximum WC allowed in the natural gas can be determined for any given temperature and pressure. Practical operating charts have been developed for guiding pipeline operators to understand and minimize IC threats in dry gas (DG) pipelines. This paper presents the probabilistic modeling approach and discusses some model results.

Updated CO2/H2S internal corrosion model of natural gas pipelines based on flow field calculations

2014 ◽  
Vol 49 (1) ◽  
pp. 39-44 ◽  
Author(s):  
Y. Cui ◽  
H.-Q. Lan ◽  
Z.-L. Kang ◽  
R.-Y. He ◽  
H. Huang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Flow Field ◽  
Gas Pipelines ◽  
Internal Corrosion ◽  
Natural Gas Pipelines ◽  
Corrosion Model

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.

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.

Assessing Hydrate Formation in Natural Gas Pipelines Under Transient Operation / Ocena zjawiska tworzenia się hydratów w warunkach nieustalonego przepływu gazu w gazociągach

2013 ◽  
Vol 58 (1) ◽  
pp. 131-144
Author(s):  
Andrzej Osiadacz
Keyword(s):  
Natural Gas ◽  
Gas Flow ◽  
Hydrate Formation ◽  
Operating Conditions ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Hydrate Phase ◽  
Real Gas Effects ◽  
Classical Thermodynamics

This work presents a transient, non-isothermal compressible gas flow model that is combined with a hydrate phase equilibrium model. It enables, to determine whether hydrates could form under existing operating conditions in natural gas pipelines. In particular, to determine the time and location at which the natural gas enters the hydrate formation region. The gas flow is described by a set of partial differential equations resulting from the conservation of mass, momentum, and energy. Real gas effects are determined by the predictive Soave-Redlich-Kwong group contribution method. By means of statistical mechanics, the hydrate model is formulated combined with classical thermodynamics of phase equilibria for systems that contain water and both hydrate forming and non-hydrate forming gases as function of pressure, temperature, and gas composition. To demonstrate the applicability a case study is conducted.

Building a Target Reliability Adaptive to China Onshore Natural Gas Pipeline

2014 ◽  
Author(s):  
Jinyuan Zhang ◽  
Zhenyong Zhang ◽  
Zhifeng Yu ◽  
Wen Wu ◽  
Yingshuai Chen
Keyword(s):  
Natural Gas ◽  
Population Density ◽  
Limit State ◽  
Operating Conditions ◽  
Risk Level ◽  
Ultimate Limit State ◽  
Gas Pipelines ◽  
Natural Gas Pipelines ◽  
Average Population Density ◽  
Average Population

To introduce and apply Reliability-Based Design and Assessment (RBDA) method to China’s onshore natural gas pipelines, China Petroleum Pipeline Engineering Corporation (CPPE) undertook a research project based on achievements from a series of researches sponsored by PRCI. RBDA method aims to maintain a consistent risk level throughout the lifecycle of pipelines by rational designs, professional operations and scientific maintenance. The basis of RBDA method is a set of risk-based reliability targets for pipelines, especially the target value of Ultimate Limit State (ULS). CPPE has developed a database for 37,000km natural gas pipelines in China and defined 148 operating conditions corresponding to various pressures, pipeline diameters, steel grades and pipeline lengths in different location classes. Failure calculation models are modified according to the corrosion and equipment impact under each specified operating condition. While calculating the failure consequences, 20,000 kilometers pipes from different locations classes were selected and statistics of average population density was made. Statistics of failure consequences were made again. Finally, the overall risk level of built natural gas pipelines was calculated. This paper introduces 148 operating conditions, failure probabilities, calculation method regarding failure consequences and average population density of all locations of different classes. Based on target reliability of pipelines set on country level, design and construction plan for newly-built pipelines are optimized by using RBDA method for rationally guiding subsequent operation and maintenance to reach the most optimal and cost-efficient plan in whole lifecycle of pipelines.

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