The ability to predict CO2 corrosion in gas lifted oil production systems, including compressor trains, lift gas distribution lines, production tubing, wellheads, and production flowlines was evaluated. Twelve cases were analyzed with two models used in the authors' company. It is shown that the models identify potential corrosion problems and that corrosion rates can be estimated, provided that all relevant data are available. These factors include temperature, flow regime, system pressure, partial pressure of CO2, condensation rates in wet gas systems, pH, and other factors influencing the saturation of the aqueous fluid with corrosion by-products. A recently introduced system to gather downhole corrosion related data is very promising in this respect. Quantification of corrosion in sour systems was not very successful, both positive and negative deviations were noted, while corrosion rates in oil/water systems were generally overestimated. The work highlighted the importance of the ability to analyze local flow disturbances, as erosive forces form a primary breakdown mechanism of protective corrosion by-product scales.

Subject
Water, Corrosion rate, Predicted corrosion rate, Corrosivity, Partial pressures, Liquids, Flow regime, Corrosion scales, Tubing, Bubbling, Corrosion modeling, Corrosion data, Oil
© 1993 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).
1993
Association for Materials Protection and Performance (AMPP)
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