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Top of Line Corrosion in Multiphase Gas Line Operational Feedbacks

Picture for Top of Line Corrosion in Multiphase Gas Line Operational Feedbacks
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The first case of top of line corrosion (TLC) in Tunu gas field was reported by Gunaltun et al in 19991. Inline
inspection (ILI) of two carbon steel pipelines distributing multiphase effluent, showed up to 50% metal
loss at 11.00 – 01.00 o’clock at several sections. Visual examination of a cut section showed that the top
of line was covered with iron carbonate layer with deep pits, and severe metal loss occurred on large
surfaces at these area.

Product Number: 51323-19486-SG
Author: Suryani, Rudi Rinaldi, Albertino Prabowo, Farih Mitraningsih, Aji Samiaji
Publication Date: 2023
$0.00
$20.00
$20.00

First Top of Line Corrosion (TLC) case was reported in 1999 in Tunu field, and since then, there were
several other pipelines from the neighboring fields, installed from 2007 to 2015 that were experiencing
TLC and was confirmed using in-line inspections (ILI). The TLC rates were found to be 0.5-1 mm/year in
average with the maximum rate of 2-3 mm/yr for gas containing CO2 up to 8.5% and around 80-90 barg
operating pressure with 80-90°C inlet temperature. Interestingly, on several pipelines, the maximum
corrosion rates happened at about 2-5 kilometers downstream the inlet risers. As part of mitigation, some
of the pipelines were designed with 10 mm corrosion allowance and when required, spray pigging and
recently, volatile corrosion inhibitor, are employed during operation at some of the pipelines. Thanks to
proper mitigations, despite high TLC rates, no adverse consequences were experienced on the pipelines.
This paper will discuss on the correlation on the field data and inspection results of the pipelines,
compares the predicted TLC rate with reality, and discusses the efficiency of various mitigation methods.
Lesson learned are also provided to illustrate the evolution of TLC mitigation strategies to ensure the
integrity of the pipelines.

First Top of Line Corrosion (TLC) case was reported in 1999 in Tunu field, and since then, there were
several other pipelines from the neighboring fields, installed from 2007 to 2015 that were experiencing
TLC and was confirmed using in-line inspections (ILI). The TLC rates were found to be 0.5-1 mm/year in
average with the maximum rate of 2-3 mm/yr for gas containing CO2 up to 8.5% and around 80-90 barg
operating pressure with 80-90°C inlet temperature. Interestingly, on several pipelines, the maximum
corrosion rates happened at about 2-5 kilometers downstream the inlet risers. As part of mitigation, some
of the pipelines were designed with 10 mm corrosion allowance and when required, spray pigging and
recently, volatile corrosion inhibitor, are employed during operation at some of the pipelines. Thanks to
proper mitigations, despite high TLC rates, no adverse consequences were experienced on the pipelines.
This paper will discuss on the correlation on the field data and inspection results of the pipelines,
compares the predicted TLC rate with reality, and discusses the efficiency of various mitigation methods.
Lesson learned are also provided to illustrate the evolution of TLC mitigation strategies to ensure the
integrity of the pipelines.

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Picture for Top of the Line Corrosion Mechanism for Multiphase Sour Gas Subsea Pipeline
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Top of the Line Corrosion Mechanism for Multiphase Sour Gas Subsea Pipeline

Product Number: 51323-18782-SG
Author: Faisal M. Al-Abbas, Marwan S Alsulami, Hadi F Al-Mansour Ayman A. Alabdullatif, Fadhel H. Asfoor, Mohammed M. Al Zamanan
Publication Date: 2023
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The hydrocarbon exploration in the ocean and deep sea was started as early as early as the 1850s, when the first drilling was carried out in California, USA. Other early oil explorations activities were later recorded in Pakistan (1886), Peru (1869), India (1890) and Dutch East Indies (1893). The development of an offshore industry is directly related to the development of subsea pipelines as well. As the industry expands towards deeper waters, the pipelines are required to have better materials, designs, operation practices and maintenance strategies to withstand the challenging environments. These pipelines are exposed to elevated temperatures, high pressures, and corrosive fluids.
Picture for Top of Line Corrosion Probabilistic Risk Analysis for Wet Sour Subsea Pipeline
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Top of Line Corrosion Probabilistic Risk Analysis for Wet Sour Subsea Pipeline

Product Number: 51319-13116-SG
Author: Faisal Al-Abbas
Publication Date: 2019
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Top of Line Corrosion (TLC) occurs in a multiphase flow when water vapor condenses at the top and the sides of the pipeline leading to a severe corrosion attack. This study investigated the probabilistic risk of TLC for wet sour gas subsea pipeline using flow modeling and corrosion predications. The flow assurance hydraulic study showed that most of water drops out over the first few kilometers as the gas is cooled and becomes much less through the rest of the offshore part until they reach onshore area where the gas temperature drops further due to Joule-Thomson effect. It was anticipated that corrosion activities will be higher at the high condensation locations. The corrosion prediction modeling revealed high corrosion severity driven by Top of Line Corrosion (TLC). In order to maintain the system integrity the internal coating supplemented by V-jet batch inhibitor injection has been selected to protect against TLC. This study has realized the challenge to apply the batch treatment as it requires process interruption to meet scraper speed limitations. Therefore the industry path forward should consider the development of novel TLC treatments that to be applied with no impact on operations.
Picture for Dual Functional Corrosion Inhibitor Design And Testing For Top-Of-Line And Bottom Of Line Corrosion
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Dual Functional Corrosion Inhibitor Design And Testing For Top-Of-Line And Bottom Of Line Corrosion

Product Number: 51322-17787-SG
Author: Larry Chen, Nihal Obeyesekere, Jonathan Wylde, Michael Sim
Publication Date: 2022
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TOL corrosion is reported to occur in large diameter wet gas pipeline in stratified flow conditions
due to low fluid velocities1. With increasing distance from the inlet, the wet gas pipeline becomes
cooler as it loses heat to the environment. Such cooling causes water, hydrocarbon, and other
high vapor pressure species to condense on the pipe wall. The upper part of the pipe will
constantly be supplied with freshly condensed water while the less corrosive water saturated
with corrosion products will be drained along the pipe wall to the bottom of the line.
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