A pitting model has been developed which provides an explanation of why acetates affect CO2 pitting corrosion. The pitting diffusion model is based on the diffusion of iron ions from the bottom to the top of the pit. To maintain electro-neutrality, negatively charged ions must migrate into the pit. For the pit to continue propagating, it must be more acidic at its bottom than at the top. The model has shown how acetates allow this to happen. The new model can be used to predict if CO2 pitting corrosion will occur provided parameters such as temperature, salt concentration, in-situ pH and acetate concentration are known. A method is presented which allow for the calculation of in-situ pH from laboratory information.

The first published data on the presence of organic acids in oilfield waters appears to have been reported by Rogers1 (1917). There was no further mention of the effect of these acids until Menaul2 (1944) addressed the problem of corrosion of tubing in gas condensate wells where there appeared to be no appreciable difference in CO2 content. Some wells corroded extremely rapidly while others showed no appreciable amount of corrosion. He was able to identify a second corrosive agent, organic acids. In view of this problem, the NGAA Committee was formed in 1944 to study corrosion in gas condensate wells. Greco and Griffin3 (1946) found that when laboratory samples of oilfield water containing organic acids were heated in the laboratory to as much as 200 ºF, there was about a 1.0 pH unit drop in the reported laboratory pH. Hackerman and Shock4 (1947) observed that the presence of acetic acid resulted in severe pitting attack along the direction of flow. Locht5 (1949) was the first to describe an analytical procedure for the detection of individual organic acids in gas condensate wells. Shock and Subdury6 performed experiments which showed that the addition of acetic acid caused the corrosion of steel in a CO2 environment to increase by 45 %.

There was a prolonged period without any work done in this area until Crolet and Bonis7 (1983) resurrected the topic by pointing out that acetates were contributing to the alkalinity of the water as well as increasing the CO2 corrosion rate. In their 1989 paper8, they make the classic statement that “there is no record of CO2 corrosion in a producing well in the absence of acetic acid”. Their explanation was that acetates confer a strong acid buffering power, thus preventing rapid neutralization due to the generation of bicarbonate. They noted that at a pH around 5.5 to 5.6 the amount of CO2 corrosion was slight. A similar observation was made by Carlson9 (1949) who described the upper pH limit of CO2 corrosion as 5.4. Alapati10 showed a plot of CO2 corrosion rate versus pH using field data and the result was that at a pH of 5.5 the corrosion rate became zero. Alapati also showed that for 18 Gulf Coast gas condensate wells.

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