This paper describes optimization of gelled and in-situ gelled HCl/formic acid systems to stimulate deep gas wells completed with super Cr-13 tubing. High temperatures encountered in deep wells and the susceptibility of super Cr-13 to severe corrosion by concentrated HCl solutions and high chloride ion concentrations render acid stimulation a very difficult task. Therefore, extensive experimental and field studies were performed to develop a cost effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of the super Cr-13 tubing.

Coreflood tests indicated that this acid system can create deep wormholes in tight reservoir cores (less than 1 md). Corrosion tests, however, indicated that protecting super Cr-13 tubulars during pumping this acid (15 wt% HCl/9 wt% formic acid) is not an easy task, especially at downhole temperatures (275°F). A very limited number of inhibitor aids were found to be effective in protecting super Cr-13 at reservoir conditions. To optimize the corrosion inhibitor package, the bottom hole temperature was measured in a few wells during acid injection.

Based on lab tests and field measurements, an acid treatment was designed and applied in the field. The treated wells responded positively to the treatment. Most importantly, the integrity of the super Cr-13 was maintained. This was confirmed from chemical analysis of well flowback samples following the treatment and measurement of the tubing inside diameter before and after the treatment. The maximum Cr concentration in the flowback sample was less than 2 mg/L. Molybdenum and nickel concentrations were less than 1 mg/L. The total iron concentration was less than 200 mg/L. This value is significantly less than that noted with wells completed with low-carbon steel tubulars.

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