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

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.

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

Corrosion Engineering Science and Technology ◽

10.1179/1743278213y.0000000102 ◽

2014 ◽

Vol 49 (1) ◽

pp. 39-44 ◽

Cited By ~ 4

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

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Monitoring X65 Steel Internal Corrosion in Humidified N2 containing H2S using Membrane-based Electrochemical Sensors

CORROSION ◽

10.5006/3454 ◽

2021 ◽

Author(s):

Timothy Duffy ◽

Derek Hall ◽

Margaret Ziomek-Moroz ◽

Serguei Lvov

Keyword(s):

Relative Humidity ◽

Natural Gas ◽

Corrosion Rate ◽

Electrochemical Sensors ◽

Element Analysis ◽

Internal Corrosion ◽

Natural Gas Pipelines ◽

Corrosion Rates ◽

Order Of Magnitude ◽

X65 Steel

We report here on a new membrane-based electrochemical sensor (MBES) that may provide an important utility in monitoring and characterizing internal corrosion of natural gas pipelines. Using this sensor, we have measured the corrosion rate of X65 steel exposed to H2S in humidified environments up to 60 °C. Consistent with our earlier CO2 study, the membrane’s conductivity did not change when exposed to H2S-contaning acidic gas. Introducing H2S consistently increased the measured corrosion rate between testing conditions, though corrosion rates were typically less than 2 μm y-1. At 30 °C, the corrosion rate doubled from 7.3 to 14 nm y-1 below a relative humidity of 30 %, and increased by an order of magnitude (0.19 μm y-1 to 1.9 μm y-1) at 55 % relative humidity, showing that the influence of H2S on corrosion increases dramatically with larger humidity. Trends with relative humidity match industry expectations: corrosion rate is low (<0.25 μm y-1) without the presence of a condensed aqueous phase, but increases as the water content of the system increases. The MBES was therefore able to captures relevant corrosion trends, even while the corrosion rates would not have presented a serious threat to any natural gas pipeline. As such, the MBES can be used to detect the onset of emerging corrosion threats before they occur. Field emission scanning electron microscopy and energy-dispersive X-ray spectroscopy confirmed that H2S reacted with the metal covered by the membrane phase, showing evidence of sulfur-rich sites on the X65 surface. In addition, finite element analysis confirmed that electrochemical measurements and data analysis techniques could be successfully used for this membrane-based sensor, despite its unconventional cell geometry.

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High Energy Natural Gas Internal Corrosion Susceptibility Analysis

Volume 4: Production Pipelines and Flowlines; Project Management; Facilities Integrity Management; Operations and Maintenance; Pipelining in Northern and Offshore Environments; Strain-Based Design; Standards and Regulations ◽

10.1115/ipc2014-33462 ◽

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

Volume 7B: Fluids Engineering Systems and Technologies ◽

10.1115/imece2015-50049 ◽

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.

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