A leak occurred in the 5-32S flowline between Junction 1 and the South Compressor Station in the Canada Limited Caroline Complex gathering system near Sundre, Alberta, due to internal wet H2S (hydrogen sulphide) and CO2 (carbon dioxide) pitting corrosion at the bottom of the pipeline. The significant contributing factors to the extremely high pitting corrosion rate, approximately 30 mm/y (1200 mpy), are considered to be unexpectedly high amounts of chloride ions in the produced well fluids, settling of the produced water under low flow conditions, high condensate/water ratio, inadequate inhibition and pigging, and insufficient monitoring programs. Corrosion mechanisms in sour gas gathering systems with significant CO2 concentration were reviewed. Preliminary findings pointed to CO2 partial pressure, not H2S, as a main corrosion rate determining factor. The steps taken to prevent similar future incidents were also reviewed.

Subject
Water, Corrosion rate, Solids, Leaks, Sour gas, Pipelines, Chloride ions, Inspection, Flowlines, Fluids, Corrosion inhibitors, Pitting, Corrosion protection
Keywords:
carbon dioxide, corrosive gas, sour gas wells, inhibition, gas transmission
© 1996 Association for Materials Protection and Performance (AMPP). All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means (electronic, mechanical, photocopying, recording, or otherwise) without the prior written permission of AMPP. Positions and opinions advanced in this work are those of the author(s) and not necessarily those of AMPP. Responsibility for the content of the work lies solely with the author(s).
1996
Association for Materials Protection and Performance (AMPP)
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