Fifteen months into the Ladyfern gas field production, produced water volumes began to surge at each well and the brine salt content increased significantly. The change in water chemistry prompted performance health checks conducted on the incumbent chemistry, re-evaluating inhibitor effectiveness relative other non foaming water soluble and water dispersible chemistries. The later inhibitors, formulated to be more dispersible in the salty brine were more effective for providing mitigating benefits against CO2 corrosion in the high total dissolved solids (TDS) brine. After re-testing inhibitors in environments simulating static, slug, and high shear flow regimes a new continuous injection product was selected for field trial. The new inhibitor was introduced into the field in late 2002 and no foaming side effects manifest throughout the production system. Field corrosion monitoring data trended before and after inhibitor change supported the decision to utilize new non foaming water soluble chemistry for managing CO2 corrosion in the higher TDS Ladyfern produced brine.

Subject
Pits, Water, Inhibitor performance, Corrosion rate, Corrosion initiation, Chemical inhibition, Fluids, Inhibitor treatment, Corrosion inhibitors, Brines, Corrosion protection, Corrosion coupons, Types of corrosion
Keywords:
wet pipeline, CO2 corrosion, salty brine, corrosion control, foam, capillary injection compatibility
© 2004 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).
2004
Association for Materials Protection and Performance (AMPP)
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