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Sour Corrosion Products Formed in High H2S Gas Wells

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Sour corrosion products could have a significant impact on the corrosion rate of carbon steel in H2S environments. It is widely believed that the different iron sulfides have different effects due to their distinct physico-chemical properties. Therefore an in-depth knowledge on the formation conditions of these polymorphous phases is of virtual importance for the understanding of sour corrosion process.Many studies have been performed to determine the key factors such as temperature solution pH H2S partial pressure and the duration of exposure in the formation of polymorphous iron sulfides; yet their formation conditions stability and phase relations are still not fully understood. This is partially due to the complex nature of sulfide and iron chemistry and their sensitiveness to oxygen. Seemingly minor changes in test conditions can often lead to dramatically different results.In this paper we present a statistic study on the corrosion products formed in some high temperature and high H2S gas wells in Saudi Arabia. Large numbers of deposits collected from downhole tubulars and wellhead manifolds are characterized for phase compositions. Results show a wide range of mineral phases and significant variation among the samples analyzed. The polymorphous iron sulfides include pyrrhotite pyrite marcasite troilite mackinawite and greigite in the order of abundance. Ferric iron compounds such as hematite magnetite akaganeite goethite and lepidocrocite are also identified in many samples. In addition ferrous iron products especially siderite are often detected. Based on the deposit structure analysis the formation mechanisms of these different types of corrosion products are discussed. It is hoped that the results from this work will contribute to further understanding of the sour corrosion process and provide value for corrosion and scale mitigation in oil and gas fields.

Product Number: 51319-12866-SG
Author: Qiwei Wang
Publication Date: 2019
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Picture for Electrochemical Model of Sour Corrosion of Mild Steel - Validation at High H2S Partial Pressures
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Electrochemical Model of Sour Corrosion of Mild Steel - Validation at High H2S Partial Pressures

Product Number: 51317--9098-SG
ISBN: 9098 2017 CP
Author: Saba Navabzadeh Esmaeely
Publication Date: 2017
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H2S corrosion mechanisms, specifically at high partial pressures of H2S (pH2S), have not been extensively studied because of experimental difficulties and associated safety issues. The current study was conducted under well-controlled conditions at pH2S of 0.05 and 0.096 MPa.
Picture for Localized Corrosion of Mild Steel under Iron Sulfide Layers in CO2/H2S Environment
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51318-10990-Localized Corrosion of Mild Steel under Iron Sulfide Layers in CO2/H2S Environment

Product Number: 51318-10990-SG
Author: Saba Navabzadeh Esmaeely / Gheorghe Bota / Bruce Brown / Srdjan Nesic
Publication Date: 2018
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Mild steel specimens (API 5L X65) were pretreated to form a pyrrhotite layer on the surface using high temperature sulfidation in oil, then exposed to a range of aqueous CO2 and H2S corrosion environments, leading to initiation of localized corrosion.

 
Picture for Fe3O4, FeCO3 or FeS - Which Corrosion Product Will Prevail at High Temperature in CO2/H2S Environments?
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Fe3O4, FeCO3 or FeS - Which Corrosion Product Will Prevail at High Temperature in CO2/H2S Environments?

Product Number: 51320-14413-SG
Author: Shujun Gao, Bruce Brown, David Young, Srdjan Nesic, Marc Singer
Publication Date: 2020
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Sweet (CO2) and sour (H2S) corrosion have continuously been a challenge in oil and gas production and transportation. Yet, some key issues are still not well understood, especially at high temperature production conditions. A CO2/H2S ratio of 500, which has been used (often inaccurately) to determine which corrosion mechanism is dominant, is probably even less valid at high temperature. The nature of the corrosion products forming at high temperature in CO2/H2S environments and their effects on the corrosion rate are not known. Finally, the impact on pipeline integrity of environmental changes between sweet and sour production conditions (simulating reservoir souring) has not been well documented. CO2, H2S, and CO2/H2S corrosion experiments were conducted at 120oC to investigate corrosion mechanisms and corrosion product layer formation at high temperature. The results show that the corrosion products were still clearly dominated by H2S under the pCO2/pH2S ratio of 550. Formation of Fe3O4, FeCO3, and FeS corrosion product layers had a direct impact on the measured corrosion rates and was dependent on the gas composition and on the sequence of exposure (CO2 then H2S and vice versa). Compared with H2S corrosion alone, the presence of CO2 could retard Fe3O4 formation in CO2/H2S mixture environment. No obvious change in steady state corrosion rate was observed when the corrosion environment was switched from CO2 to H2S and vice versa. 
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