Flow-Induced Carbon Dioxide and Hydrogen Sulfide Corrosion Studies Using the Dynamic Field Tester in Crude Oil Wells

Hernández, S. E.; Rincon, Hernan; Vera, Jose

doi:10.5006/1.3287673

Cited by 6 publications

(4 citation statements)

References 8 publications

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“…This fact can be correlated with the higher oil viscosity. [5] The higher the viscosity, the higher the shear stress on the surface of the specimens, which promotes, together with other flow parameters, constant removal of the iron carbonate layer, explaining the higher corrosion rates for HO both for 0°and 45°. [10,28,31] 4.2 | Slug-bubble size, velocity, and frequency as a function of oil viscosity, pipe inclination, and CO 2 and H 2 S partial pressure…”

Section: Corrosion Rate As a Function Of Oil Viscosity Pipe Inclination And Co 2 And H 2 S Partial Pressurementioning

confidence: 97%

“…However, three-phase studies using crude oil and the water cut 80% have not been found. [5] A hypothesis can be raised based on the specific information obtained during the experimental tests. The careful inspection of the specimens after the tests, showed the presence of a film of the emulsified mixture of water and oil, with high viscosity, on the surface of the specimens.…”

Section: Corrosion Rate As a Function Of Oil Viscosity Pipe Inclination And Co 2 And H 2 S Partial Pressurementioning

confidence: 99%

“…In this way, the understanding of the corrosion mechanism of materials used in subsea production is crucial for the design of subsea oil production equipment including pipelines. [3,5,6] The fundamental question requires the understanding of the principles related to flow modeling, which includes the individual phase mass transport, momentum, and energy equations applicable to multiphase flows. For modeling multiphase flows, there is not any universally applicable methodology that is independent of the flow pattern.…”

Section: Introductionmentioning

confidence: 99%

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Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Pereira

Taqueda

et al. 2021

Materials & Corrosion

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In the offshore oil and gas industry, mainly focusing on the use of rigid or flexible pipes of subsea infrastructure applied to risers or flowlines, one of the greatest difficulties is the interpretation of the combined effects of the various correlated phenomena (hydrodynamic effects of intermittent flow, the effects of corrosivity of the environment in addition to variations in pressure, temperature, and dynamic loading). On the basis of this scenario, defining the degree of severity of each of the correlated system variables becomes of fundamental importance for establishing reliable criteria for selecting materials for subsea application. The established flow pattern directly affects the corrosion rate (or the pipe material mass loss), but the balance of other variables including possible changes in the physical and transported fluid chemical properties may increase the damage up to an order of magnitude, which is a piece of information normally not foreseen in design criteria. Therefore, to improve the understanding of the corrosion study influenced by multiphase flow, a testing loop was designed and assembled at the Corrosion and Protection Laboratory of the Institute for Technological Research, in which API X80 steel coupons were positioned in locations with a 0°and 45°inclinations. Tests were conducted by varying the partial pressure of the gaseous phase containing blends of CO 2 and H 2 S with N 2 balance, mixed with the liquid phase containing light oil and heavy oil in water with salinity (NaCl)simulating oil well conditions with 80% water cut. The main objective of this study is to establish models that can predict the corrosion intensity in conditions close to those obtained experimentally. To achieve results, the multiple regression and Box-Cox transformation methods were applied. These models will make possible damage prediction and optimization of matrix parameters for the multiphase-loop test.

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Section: Corrosion Rate As a Function Of Oil Viscosity Pipe Inclination And Co 2 And H 2 S Partial Pressurementioning

confidence: 97%

Section: Corrosion Rate As a Function Of Oil Viscosity Pipe Inclination And Co 2 And H 2 S Partial Pressurementioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Pereira

Taqueda

et al. 2021

Materials & Corrosion

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“…When iron from the steel undergoes oxidation in the presence of CO 2 and water (H 2 O), resulting in the formation of ferrous ions (Fe 2+ ), hydrogen gas (H 2 ) is evolved because of reduction of hydrogen ions present in the water phase . The oil phase itself does not lead to corrosion and can even prevent it. − In oil–water flow within a pipeline oriented horizontally at low flow rates, the water phase is present as a separate layer that flows in the lower section of the pipe. This represents a stratified flow pattern since the gravitational force becomes dominant over turbulent force.…”

Section: Introductionmentioning

confidence: 99%

Experiments and Molecular Simulations to Study the Effect of Surface-Active Compounds in Mixtures of Model Oils on CO₂ Corrosion during Intermittent Oil–Water Wetting

Norooziasl,

Qadikolae,

Young

et al. 2024

Langmuir

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Intermittent oil−water wetting can have a significant effect on the internal corrosion of steel pipelines. This paper presents a combined experimental and molecular modeling study of several influential factors on the surface properties and corrosion behavior of mild steel in CO 2 environments. The influence of different model oils and select surfaceactive compounds (myristic acid, cyclohexane butyric acid, and oleic acid) on the corrosion behavior of carbon steel during intermittent oil−water wetting was determined by measuring the corrosion rate after intermittent wetting cycles. The interfacial tension measurements were performed to study the incorporation of the oil phase along with surface-active molecules in the protective layer formed on the specimen surface. Results showed that the interfacial tension for an aromatic oil−water interface is lower than that for an aliphatic oil−water interface. To understand this result, molecular dynamics simulations of oil−water interfaces were performed in the presence of surface-active molecules and different oils to analyze the structure of the layer formed at the interface. The simulations supported the hypothesis that aromatic molecules are less structured at the interface, which results in the incorporation of more water molecules into the protective layer formed at the steel surface, causing a higher corrosion rate. On the other hand, the simulations revealed that myristic acid in an aliphatic oil forms a well-aligned structure at the interface, devoid of any water molecules. This is in agreement with the hypothesis that the linear molecular structure of myristic acid favors the alignment of molecules at an aliphatic oil−water interface, resulting in a lower interfacial tension and more effective corrosion mitigation as compared to the other two nonlinear compounds tested. It is concluded that an important factor controlling the corrosion behavior is the molecular structure of the oil−water interface, which is adopted by the steel surface layer through the Langmuir−Blodgett process.

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Internal corrosion studies in hydrocarbons production pipelines located at Venezuelan Northeastern

Biomorgi¹,

Hernández²,

Marin³

et al. 2012

Chemical Engineering Research and Design

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Flow-Induced Carbon Dioxide and Hydrogen Sulfide Corrosion Studies Using the Dynamic Field Tester in Crude Oil Wells

Cited by 6 publications

References 8 publications

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Experiments and Molecular Simulations to Study the Effect of Surface-Active Compounds in Mixtures of Model Oils on CO₂ Corrosion during Intermittent Oil–Water Wetting

Internal corrosion studies in hydrocarbons production pipelines located at Venezuelan Northeastern

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Flow-Induced Carbon Dioxide and Hydrogen Sulfide Corrosion Studies Using the Dynamic Field Tester in Crude Oil Wells

Cited by 6 publications

References 8 publications

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO2/H2S environment

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO2/H2S environment

Experiments and Molecular Simulations to Study the Effect of Surface-Active Compounds in Mixtures of Model Oils on CO2 Corrosion during Intermittent Oil–Water Wetting

Internal corrosion studies in hydrocarbons production pipelines located at Venezuelan Northeastern

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Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Prediction models for multiphase‐flow‐induced corrosion of API X80 steel in CO₂/H₂S environment

Experiments and Molecular Simulations to Study the Effect of Surface-Active Compounds in Mixtures of Model Oils on CO₂ Corrosion during Intermittent Oil–Water Wetting