Abstract
Corrosion damage to L80 carbon steel downhole production tubing recovered from four Khuff gas wells was assessed. The carbon steel production tubing failed prematurely due to either sour general corrosion or sour pitting corrosion. Observed corrosion rates varied from 1.25 to 6.25 mm/y (50-250 mpy). Sour general corrosion rates were relatively mild, less than 50 mpy, but sour pitting corrosion penetration rates were greater than 125 mpy. Producing relatively dry gases, the wells were completed with 4½-in L80 carbon steel production tubing having a wall thickness of 0.290 inch would experience tubing-casing-annulus communication (TCA) due to sour corrosion in approximately 2-6 years. Contrary to industry practice, sour gases with high H2S/CO2 ratios greater than 0.5 seem not to form protective films on the carbon steel production tubing. In fact, corrosion products were tightly adhered on the tubing but porous, providing only partial corrosion protection. However, when pitting corrosion does not occur and the wells are relatively dry, the L80 carbon steel production tubing is still a viable and economical material for the Khuff gas wells provided that the work-over (WO) interval can be extended to more than 5 years. Corrosion products consisted of multiple layers believed to be related to numerous shut-ins after well completion. Evidently during well shut-ins sour corrosion rapidly stopped and the corrosion products formed a distinctive discernable layer. When gas demand is low, shutting in the wells rather than reducing the gas flow rate is preferable from the standpoint of corrosion management. As the gas flow rate increased, the higher gas velocities facilitated better mixing between condensed water and liquid hydrocarbons on the ID surface of the carbon steel production tubing, which in turn significantly reduced sour corrosion.
