Successful Long Duration Batch Treatment of Gas Well to Prevent Corrosion Challenges and Solutions

Abstract

Results are presented on a long duration batch treatment using corrosion inhibitor in deep sour gas wells. This paper discusses the lessons learned during this implementation. An innovative method of placing downhole corrosion coupon was used to monitor the field result. Gauge cutter runs indicate a reduced accumulation of iron sulfide scale for the batch treatment interval. The selection of the corrosion inhibitor involved corrosion testing at high shear and high temperature with hydrogen sulfide and carbon dioxide and high temperature, high pressure core flood tests. Corrosion tests were done in a rotating cage at low and high temperatures, high partial pressures of carbon dioxide (CO2) and hydrogen sulfide (H2S) and a different rotation rates. Core flood experiments were conducted on a 6-inch-long limestone core at 280° F and 5000 psi. The stability of the neat corrosion inhibitor at different temperatures was confirmed in a laboratory umbilical injection system. The batch treatment procedure was designed to ensure a sufficient amount of chemical to coat tubing completely. The batch treatments were monitored in the field using a new downhole corrosion and scale monitoring tool. Initial screening of corrosion inhibitor testing at high temperatures, with high partial pressures of H2S and CO2 using both X65 and T95 coupons at different rotation rates indicated that the selected corrosion inhibitor was a good candidate for treating a sour gas well. Core flood testing showed that the permeability of nitrogen through limestone at 280° F and 5000 psi was 1.23 md with a standard deviation of 0.06 md. The permeability of gas through limestone at residual corrosion inhibitor saturation was 1.32 md with a standard deviation of 0.06 md. Capillary testing of the product was conducted at 166° C (350° F) and 5000 psi for 7 days. The chemical passed the test and no sign of differential pressure increase or product instability. The product was used in two sour gas wells. No formation damage was observed with batch treatment. Downhole monitoring coupons were used to monitor the trial in instances where corrosion inhibitor was and was not used. The coupon experienced generalized corrosion between 5 -10 μm in 3 months (0.8 -1.6 mpy) when corrosion inhibitor was not used. The coupon that had a batch treatment experienced generalized corrosion between 3-8 μm in 5 months (0.3 -0.8 mpy). Slight pitting corrosion was found in both coupons. For the trial without inhibitor, pitting features between 20 to 25 μm was found. This corresponds to pitting corrosion rates between 3 to 4 mpy. In the coupon that was batch treated with corrosion inhibitor, one pit of 13 μm was found. This corresponds to a rate of pitting corrosion of 1.2 mpy. It was found that gauge cutters would travel to longer depths in the intervals after batch treatment when compared with intervals where no chemical was used. This was good indication of reduced scale formation index. The application is useful to prevent sour corrosion and iron sulfide scaling (ferric source). The field trial utilized novel downhole monitoring technology and is an instance of a successful long duration corrosion inhibitor treatment that did not damage the carbonate formation.