Abstract
This paper discusses Mobil Oil Indonesia Inc. (MOI)'s experience with simulation of future wellbore corrosion in actual wells under production. The work was done to complement results of a three-year study, where future wellbore corrosion was modelled in laboratory simulated Arun Field type wellbore environments.
In the Arun Field, the wellbore environment is constantly changing with time, due to continuing exploitation of the field and associated depletion of the reservoir. In particular, the reservoir pressure has been gradually decreasing, resulting in lower wellhead pressures and temperatures than in the initial stages of the field production. At the same time, the amount of condensed water is gradually increasing. All production wells in the Arun Field are equipped with 7 inch (177.8 mm), 35 ppf (52.2 kg/m)/ L-80 Grade, Carbon Steel Level II tubing. The wells have been produced such that the flowing wellhead temperature was maintained above 300°F (150°C) by keeping the flowrate above 50 MMSCFD (1,415 MSCM/D). Maintaining such high flowing wellhead temperatures will not be feasible in the future, towards the end of the life of the field.
It has been demonstrated in the laboratory, that the L-80 type carbon steel tubular materials may experience excessive corrosion rates in Arun type environments at reduced temperatures. Favorable conditions for tubing corrosion were observed in the laboratory when the flowstream temperature decreased to approximately 250°F (121°C) and the flowstream velocity was high. Three Arun Field producing wells were purposely operated in a mode that favored wellbore corrosion, as it was demonstrated in the laboratory. In particular, the flowing temperature in the wellbore was kept in the critical temperature range. In addition, the wellstream velocity in one of the test wells was increased in stages to study its effects on wellbore corrosion rates.
