Operators are experiencing severe pitting corrosion on horizontal casing in the Eagle Ford region. The most severe pitting was estimated at -240 mpy (~6.60 mm/yr) based on linear extrapolation. For the well of interest the toe sleeve was opened and perforated to perform a small acid fracturing job. The well was then filled with 1% KCI containing biocide. This process leaves the well open to the reservoir but in a non-flowing condition. Five months after initial completions work, corrosion was observed when completions were resumed. Two limited inspections were performed showing pitting near the middle of the horizontal section with no corrosion closer the vertical section. The question was to determine if the damage in the horizontal portion of the casing could be due to the fluid in the well (1 wt% KCI) mixing with formation fluids (containing 1 mol% CO2 and formation brine which included high amounts of acetic and propionic acids). Using aqueous modeling, it is possible to simulate the thermodynamic equilibrium species present in the well and then simulate the corrosion that would occur in the presence of those species.
An operator experienced severe pitting on the casing of a well in the Eagle Ford region. One well was exposed to a reservoir that is known to contain acetic acid (149-306 ppm) and CO2 (1 mol%). Acetic acid is known to accelerate corrosion rates1-4 and disrupt the protective nature of an iron carbonate films at elevated temperature.5 In addition acetic acid is known to accelerate the dissolution of carbonates.6 CO2 has been known to cause corrosion in oil and gas since first reported by Bacon and Brown in 19427 and numerous papers have been published on the subject since that time. This study will simulate the effects of exposing a horizontal to a reservoir containing acetic acid and CO2 to determine if small amounts of corrosive agents from the reservoir could cause corrosion damage in the horizontal.