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Corrosion Mitigation Of Deepwater, 143-Km Long Multiphase Pipelines

Product Number: 51321-16520-SG
Author: Alyn Jenkins/ Marcus Rossiter/ William Cardwell/ Michael Reid/ Brian Messenger
Publication Date: 2021
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The Laggan-Tormore gas field is a deepwater development located 125 km off the West Coast of the UK Shetland Islands, in the North Atlantic. The field consists of five subsea production wells tied back to subsea manifolds that are connected to two 18-in multiphase pipelines. In addition, two other subsea templates consisting of three subsea wells are connected to the field via a 35-km tieback. The gas field development is unique for the UK Offshore Northern Sector in that produced fluids and gas are not processed offshore. Instead, the fluids and gas are transported via the two 18-in diameter, 143-km multiphase pipelines from the offshore fields to an onshore gas plant on Shetland for processing. The multiphase pipelines are constructed from carbon steel, and therefore, to prevent corrosion an inhibitor was required. Monoethylene glycol is injected in the field at the subsea manifolds for hydrate control, and to facilitate the delivery of the corrosion inhibitor, chemical is injected in combination with the glycol. Mitigation of corrosion in the Laggan-Tormore multiphase pipelines presented several challenges. The glycol used in the field is recycled via a regeneration unit. Consequently, the corrosion inhibitor would have to withstand the high temperatures within the unit and not suffer physical degradation or a decrease in efficacy when exposed to the unit. Considering there is only one corrosion inhibitor injection location for each multiphase pipeline, the inhibitor is required to be transported the whole length of the multiphase pipeline and provide protection of its entirety. Finally, there is no corrosion monitoring in place in the subsea pipelines. Therefore, to determine if the pipelines are under corrosion control, analysis of the produced fluids to provide an indirect measurement of the corrosion rate was required, including iron counts, corrosivity measurements of the produced fluids, and corrosion inhibitor residual analysis. This paper discusses the laboratory work carried out to develop a corrosion inhibitor for this application, details its deployment and provides an overview of the ongoing monitoring performed to ensure the integrity of the multiphase pipelines.

Key words: corrosion inhibitor, multiphase, deepwater, subsea, glycol regeneration and desalination 

The Laggan-Tormore gas field is a deepwater development located 125 km off the West Coast of the UK Shetland Islands, in the North Atlantic. The field consists of five subsea production wells tied back to subsea manifolds that are connected to two 18-in multiphase pipelines. In addition, two other subsea templates consisting of three subsea wells are connected to the field via a 35-km tieback. The gas field development is unique for the UK Offshore Northern Sector in that produced fluids and gas are not processed offshore. Instead, the fluids and gas are transported via the two 18-in diameter, 143-km multiphase pipelines from the offshore fields to an onshore gas plant on Shetland for processing. The multiphase pipelines are constructed from carbon steel, and therefore, to prevent corrosion an inhibitor was required. Monoethylene glycol is injected in the field at the subsea manifolds for hydrate control, and to facilitate the delivery of the corrosion inhibitor, chemical is injected in combination with the glycol. Mitigation of corrosion in the Laggan-Tormore multiphase pipelines presented several challenges. The glycol used in the field is recycled via a regeneration unit. Consequently, the corrosion inhibitor would have to withstand the high temperatures within the unit and not suffer physical degradation or a decrease in efficacy when exposed to the unit. Considering there is only one corrosion inhibitor injection location for each multiphase pipeline, the inhibitor is required to be transported the whole length of the multiphase pipeline and provide protection of its entirety. Finally, there is no corrosion monitoring in place in the subsea pipelines. Therefore, to determine if the pipelines are under corrosion control, analysis of the produced fluids to provide an indirect measurement of the corrosion rate was required, including iron counts, corrosivity measurements of the produced fluids, and corrosion inhibitor residual analysis. This paper discusses the laboratory work carried out to develop a corrosion inhibitor for this application, details its deployment and provides an overview of the ongoing monitoring performed to ensure the integrity of the multiphase pipelines.

Key words: corrosion inhibitor, multiphase, deepwater, subsea, glycol regeneration and desalination