Design of electrical submersible pumps in methane hydrate production wells: A case study in Nankai trough methane hydrates

Abstract

Gas hydrate industry aims to conduct long-term gas hydrate production trials after gaining the experiences in short-term gas hydrate production trials. Electrical submersible pumps (ESP) were mostly chosen in gas hydrate production trials to depressurize gas hydrate reservoirs. However, there is a knowledge gap about the usage and design of ESP systems in gas hydrate wells. Therefore, in this study, it is aimed to design ESP systems in methane hydrate production well in the conditions of Nankai Trough (Japan) methane hydrate reservoirs. For this purpose, a set of python codes was written to design ESP in the case study gas hydrate well and also HEP simulator was used to predict gas hydrate formation risks along the wellbore during gas production from methane hydrates via ESP production string. It was shown that high variances in water production rates (50–794 m³/day) affect the pump performance negatively, especially in the outside of suggested pump working flow rates. Moreover, pump efficiencies decrease from 70 s% to 20 s% in the outside of pump working flow rates due to huge variances in water flow rates during production. Different than conventional gas wells, the temperature rise generated by the motor is important to avoid any gas hydrate formation in gas hydrate well, which was affected by the operating frequency. Above 40 Hz of operating frequency, well temperature increases (nearly 0.65–1.75°C) by the motor with increasing frequency, which is good for the prohibition of gas hydrate formation in the well. In terms of pump power requirements, there is no difference of producing water at sea surface and releasing produced water to the seafloor. According to the methane hydrate equilibrium predictions in the wellbore during production with ESP, methane hydrate is not like to form in the design conditions. However, with ESP malfunction, methane hydrate might form inside the well due to increasing wellbore pressure and decreasing well temperature.