Acid fracturing treatments are used to enhance gas production from tight, deep carbonate reservoirs in Saudi Arabia. The produced gas has a regional variation between 0 and 10 mol% H2S. This variation in H2S content has impacted the metallurgy of well tubulars used in these areas. Gas wells in the high H2S area are completed with low-carbon steel (L-80 and C-95); those in the low H2S area are completed with super Cr-13 tubulars.
Acid systems used to fracture these wells included: regular, emulsified, and in-situ gelled acids, all based on 28 wt% HCl. However, 15 wt% HCl – 9 wt% formic acid was used to stimulate wells completed with super Cr-13 tubing. High temperatures (275°F) encountered in deep wells, the presence of high H2S content and the use of large volumes of concentrated acids render corrosion control of tubulars a very difficult task.
Experiments were performed to develop a cost-effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of well tubulars. Acid fracturing treatments were monitored in the field and well flow back samples were collected following these treatments. The concentrations of key ions were measured in these samples including iron and manganese for completions with low-carbon steel tubulars and chrome, molybdenum, and nickel for completions with super Cr-13.
Analysis of flow back samples following the initial acid fracturing treatments showed that the return samples contained high concentrations of acid (up to 16 wt% HCl) and total iron (up to 20,000 mg/l). The presence of iron was a major concern during acid fracturing treatments. Modifications of the corrosion inhibitors package, increasing soaking time and over flush volume resulted in better results. Most importantly, the integrity of well tubulars was maintained. This paper discusses lab studies and application of these modifications in the field.