Corrosion product iron counts

Similar results were presented in [9]. In uninhibited CO2 environments it was observed that in general the P-factors were of the order of 15-20 mV for pH-statted test procedures. However, as soon as a corrosion product layer formed, the factors increased. It is for this reason that the original PAIR -meter by Petrolite pre-programmed a P-factor of 37 mV based on extensive laboratory and field calibrations [45]. Newer commercial instruments allow the user to dial in a value for the p-factor. However, this presupposes that the Tafel slopes are known, and since these cannot be reha-bly determined as indicated above, the user is still left to guess, unless calibration procedures are in place, such as weight loss determinations or iron counts. 

NACE Recommended Practice RP 0192-92, Monitoring Corrosion in Oil and Gas Production with Iron Counts (item 21053). 

In some wells, it is possible to obtain an indication of downhole corrosion by analysis of produced fluids for iron. This method is described in NACE Standard Practice for Monitoring Corrosion in Oil and Gas Production with Iron Counts (RP0192). It has been used effectively for monitoring inhibition in wells where corrosion follows a general, nonlocalized pattern, and where the corrosion products are water-soluble (e.g., in sweet wells). 

Of primary concern is the amount of iron dissolved in the water in systems containing little or no oxygen. This means a single speck of solid corrosion product can lead to incorrect results. It is advisable to filter the sample to remove any suspended solids. Also, exposure of the water to air will cause all of the dissolved iron to precipitate as ferric hydroxide, Fe(OH)3 Therefore, good iron counts should be run on samples immediately after sampling, or the sample acidified with hydrochloric acid to prevent precipitation. 

Frequently iron counts are used as a means of monitoring corrosion and the effectiveness of inhibitor treatments in gas wells. Interpreting iron counts without supporting data can he misleading. In order to properly assess iron counts the chloride content, rate of water production, and information as to hydrogen sulfide or carbon dioxide content of gas is necessary. 

Water production is now a combination of formation and condensed water with corrosion possible over the entire tubing string and well head. With COj or H2S, severity is approximately the same as above. Iron counts of 50 to 150 are acceptable, providing proper metallurgy has been selected for the well head. 

The water is not primarily from the formation corrosion will occur over the entire tubing string and well head.With only trace amounts of CO2 and HjS, severity will decrease with increasing water production. However, inhibition may become more difficult due to the tendency of water to desorb or wash the inhibitor film from equipment. Iron counts of 50 or less are desirable with permissible count decreasing as water increases. 

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