Field Evaluation of Downhole Corrosion Mitigation Methods at Prudhoe Bay Field, Alaska

Abstract

Abstract Increasing downhole corrosion failures are observed in large number of carbon steel (CS) completion wells at Prudhoe Bay field in Alaska. The main corrosion damage mechanism was identified as CO2 corrosion (sweet corrosion), caused by relatively high temperature (200 - 220 °F) and high CO2 content (12%) in the reservoir gas. Different downhole corrosion mitigation methods, including corrosion inhibitor batch treatments, gas lift corrosion inhibitor treatments, chemical treater strings, internally plastic coated tubing, and 13Cr tubing were evaluated in the field. The relative effectiveness and economics of different downhole corrosion mitigation methods were compared based on extensive corrosion monitoring data from weight loss coupons, downhole and surface electrical resistance (ER) probes, caliper surveys, and well completion/ workover records. Study results show that corrosion inhibitor batch treatments have limited treatment life (<10 days) in higher water cut wells. Inhibitor film persistency (treatment life) is inversely proportional to the daily water production rate. Except for very low water cut wells, quarterly or monthly corrosion inhibitor batch treatments are not cost effective at Prudhoe Bay field. Gas lift corrosion inhibition, on the other hand, can potentially provide cost effective protection against downhole corrosion in higher water cut gas lift wells. Study results also show that chemical treater strings and 13Cr tubing have excellent corrosion resistance performance and they are recommended for future new completion if high water production rates and/or long completion service life are expected.