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Corrosion Inhibitor Film Stability Under High Gas Velocity Conditions of Subsea Wet Gas

This paper details challenges of high pressure sour gas projects with high salinity and provides cases of field history, explanation regarding material selection framework and technical challenges during the design, execution and operating phases of sour service projects.

Product Number: 51317--9247-SG
ISBN: 9247 2017 CP
Author: Bei Wang
Publication Date: 2017
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With the development of the deep water offshore gas field in China recent years long distance subsea gas pipelines have been built up and flow assurance becomes more and more important. The need to maintain gas production at reducing reservoir pressure had already resulted in much higher gas velocities in the field. However higher gas velocity leads to higher wall shear stress that can be detrimental to the inhibitor adsorbing on the internal surface of pipeline which will increase the corrosion risk especially for wet gas transportation. Corrosion is always recognized as one of the biggest flow assurance challenges of natural gas fields. During the pipeline design and maintenance it is not enough to only use the equations of the limitation for the maximum erosional velocity from API RP 14E to deal with the balance of pipeline diameter flow rate and the corrosion inhibitor film stability and effectiveness. In order to get more information of the relationship between flow and inhibitor for wet subsea pipeline a wet gas flow loop was employed to simulate typical flow conditions of subsea gas pipeline in this paper as well as the research of corrosion behaviors before and after inhibitor injection. The stability of inhibitor film on the pipeline steel’s surface under high gas velocities under the CO2 wet gas corrosion environment was evaluated. The influence of pipeline operating parameters such as gas velocity wall shear stress CO2 pressure liquid holdup and inhibitor dosage was investigated during the flow loop tests. The results give the recommendation of the gas velocity and the inhibitor limits of the subsea gas pipeline.

Key words: Sour, H2S, corrosion resistant alloys (CRA), quality, application limits, quality improvement

 

With the development of the deep water offshore gas field in China recent years long distance subsea gas pipelines have been built up and flow assurance becomes more and more important. The need to maintain gas production at reducing reservoir pressure had already resulted in much higher gas velocities in the field. However higher gas velocity leads to higher wall shear stress that can be detrimental to the inhibitor adsorbing on the internal surface of pipeline which will increase the corrosion risk especially for wet gas transportation. Corrosion is always recognized as one of the biggest flow assurance challenges of natural gas fields. During the pipeline design and maintenance it is not enough to only use the equations of the limitation for the maximum erosional velocity from API RP 14E to deal with the balance of pipeline diameter flow rate and the corrosion inhibitor film stability and effectiveness. In order to get more information of the relationship between flow and inhibitor for wet subsea pipeline a wet gas flow loop was employed to simulate typical flow conditions of subsea gas pipeline in this paper as well as the research of corrosion behaviors before and after inhibitor injection. The stability of inhibitor film on the pipeline steel’s surface under high gas velocities under the CO2 wet gas corrosion environment was evaluated. The influence of pipeline operating parameters such as gas velocity wall shear stress CO2 pressure liquid holdup and inhibitor dosage was investigated during the flow loop tests. The results give the recommendation of the gas velocity and the inhibitor limits of the subsea gas pipeline.

Key words: Sour, H2S, corrosion resistant alloys (CRA), quality, application limits, quality improvement

 

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