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

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

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 development of an offshore industry is directly related to the development of subsea pipelines as well. Top of the Line Corrosion (TLC) is a phenomenon of global importance in the subsea pipelines. TLC is driven by the condensation of water enriched with corrosive gases. 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. The condensation happens due to the heat exchange occurring between the pipe and surroundings seawater. TLC corrosion can be dominated by either the sweet corrosion or sour corrosion mechanism. Where sweet mechanisms dominate, the mechanism is dependent upon having a high condensation rate in excess of 0.25g/m=2s to maintain corrosion, as at lower rates, corrosion is stifled by the corrosion products within the condensing area. For the sour TLC mechanism, there is no minimum condensation rate beneath which TLC is stifled. In fact, there is little knowledge about the sour TLC in the literature.
This study was conducted to determine the TLC risk for new sour gas pipeline network. Experiments were performed in order to determine the effect of temperature, water condensation rate, and organic
acid on TLC corrosion and the formation of iron sulfide (FeS) scale. The results confirmed that TLC corrosion rates in sour environments are mainly dependent on iron sulfide scale characteristics which are a function of temperature. The weight loss maximum corrosion rate was 0.28 mm/y at gas temperature of 67 oC. The coupons surfaces were entirely covered by a dense iron sulfide corrosion product layer that seemed to have provided some natural corrosion protection. However, at gas temperature of 40 oC, the maximum corrosion rate was 1.02 mm/y. The entire surface was covered by a 50-100 μm thick iron sulfide corrosion product layer that seemed to have provided very little corrosion protection. In order to
maintain the system integrity, the internal coating supplemented by V-jet batch inhibitor injection has been selected to protect against TLC. 

The development of an offshore industry is directly related to the development of subsea pipelines as well. Top of the Line Corrosion (TLC) is a phenomenon of global importance in the subsea pipelines. TLC is driven by the condensation of water enriched with corrosive gases. 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. The condensation happens due to the heat exchange occurring between the pipe and surroundings seawater. TLC corrosion can be dominated by either the sweet corrosion or sour corrosion mechanism. Where sweet mechanisms dominate, the mechanism is dependent upon having a high condensation rate in excess of 0.25g/m=2s to maintain corrosion, as at lower rates, corrosion is stifled by the corrosion products within the condensing area. For the sour TLC mechanism, there is no minimum condensation rate beneath which TLC is stifled. In fact, there is little knowledge about the sour TLC in the literature.
This study was conducted to determine the TLC risk for new sour gas pipeline network. Experiments were performed in order to determine the effect of temperature, water condensation rate, and organic
acid on TLC corrosion and the formation of iron sulfide (FeS) scale. The results confirmed that TLC corrosion rates in sour environments are mainly dependent on iron sulfide scale characteristics which are a function of temperature. The weight loss maximum corrosion rate was 0.28 mm/y at gas temperature of 67 oC. The coupons surfaces were entirely covered by a dense iron sulfide corrosion product layer that seemed to have provided some natural corrosion protection. However, at gas temperature of 40 oC, the maximum corrosion rate was 1.02 mm/y. The entire surface was covered by a 50-100 μm thick iron sulfide corrosion product layer that seemed to have provided very little corrosion protection. In order to
maintain the system integrity, the internal coating supplemented by V-jet batch inhibitor injection has been selected to protect against TLC. 

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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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