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.
Introduction
Prudhoe Bay field, located on the north slope of the Alaska Range, is the largest oil field in North America1. The field was discovered in 1968 and commercial oil production started in 1977. Carbon steel (CS) metallurgy was selected for most of the downhole tubular and topside flowlines during field startup. No significant corrosion problems were encountered initially. However, increasing downhole and topside corrosion problems were observed since the startup of waterflood (WF) and miscible injectant (MI) enhanced oil recovery projects in the early 1980's2–4. The main corrosion damage mechanism was identified as sweet corrosion (CO2 corrosion), caused by relatively high temperature (200 – 220°F) and high CO2 content (12%) in the reservoir and MI gas2.
An active corrosion monitoring and mitigation program has been in place since late 1980's. To date, the topside flowline corrosion problems are largely under control through many years of continuous improvement in corrosion inhibitor performance and thorough field wide installation of continuous corrosion inhibitor injection systems at the wellhead of every production well.
The downhole corrosion problems, on the other hand, have not been fully brought under control. The purposes of this study were to review historical downhole corrosion trends in the western operating area (WOA) of the field; to compare the relative effectiveness of different downhole treatment methods; and to recommend future downhole corrosion control strategy for the remainder life of the field.
