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Selection and Testing of Fusion Bond Epoxy Coating for High Pressure Pipelines with H2S and CO2 Acid Gases

Picture for Selection and Testing of Fusion Bond Epoxy Coating for High Pressure Pipelines with H2S and CO2 Acid Gases
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New gas field expansion will provide offshore facilities to process non-associated gas, where the new
gas gathering system takes non-associated gas from offshore gas wells and transports it through
pipeline to onshore processing plants. The gas is very corrosive due to high levels of H2S and CO2 acid
gases content. Further hydrate control is achieved by injecting mono ethylene glycol (MEG).

Product Number: 51323-19482-SG
Author: Sameer Ayyar
Publication Date: 2023
$0.00
$20.00
$20.00

Selection of materials for high pressure gas pipelines is driven by the reservoir conditions. Designers
calculate the expected corrosion rate per year based on the reservoir conditions including pressure,
temperature, water loading, H2S and CO2 acid gases content. The calculated corrosion rate is then
multiplied by the design life, and material selection is performed. When corrosion is expected to exceed
a certain level, corrosion resistant alloy (CRA) material or CRA weld overlay on carbon steel are
selected. In cases of lower corrosion rates, carbon steel with a higher wall thickness (corrosion
allowance) is selected.


For an offshore field with up to 8% H2S and 6.5% CO2, the choice of material based on calculated
corrosion rates had been CRA material. A design optimization was performed to utilize carbon steel
material with Fusion Bond Epoxy (FBE) coating instead of CRA material. The reservoir conditions were,
however, beyond the conventional limits of FBE coating with respect to partial pressures of acid gases
of H2S and CO2. A specialized testing and qualification program using 14 samples (8 samples for pipe
body and 6 samples for girth weld) was performed to qualify FBE coating for the high-pressure gas.


This paper summarizes FBE testing qualification program and coating test results for pipe body and
girth weld for the given challenging reservoir conditions.

Selection of materials for high pressure gas pipelines is driven by the reservoir conditions. Designers
calculate the expected corrosion rate per year based on the reservoir conditions including pressure,
temperature, water loading, H2S and CO2 acid gases content. The calculated corrosion rate is then
multiplied by the design life, and material selection is performed. When corrosion is expected to exceed
a certain level, corrosion resistant alloy (CRA) material or CRA weld overlay on carbon steel are
selected. In cases of lower corrosion rates, carbon steel with a higher wall thickness (corrosion
allowance) is selected.


For an offshore field with up to 8% H2S and 6.5% CO2, the choice of material based on calculated
corrosion rates had been CRA material. A design optimization was performed to utilize carbon steel
material with Fusion Bond Epoxy (FBE) coating instead of CRA material. The reservoir conditions were,
however, beyond the conventional limits of FBE coating with respect to partial pressures of acid gases
of H2S and CO2. A specialized testing and qualification program using 14 samples (8 samples for pipe
body and 6 samples for girth weld) was performed to qualify FBE coating for the high-pressure gas.


This paper summarizes FBE testing qualification program and coating test results for pipe body and
girth weld for the given challenging reservoir conditions.

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