Risk Assessment of Annular Pressure Caused by Tubing Leakage in Offshore Gas Wells with High CO2

Abstract

CO2 sequestration is a kind of technology that can effectively mitigate the greenhouse effect, and the wellbore integrity of the storage system is the key issue to ensure successful CCUS. Failure to timely diagnose tubing leakage in offshore gas wells with high CO2 will lead to annular pressure risk and wellbore corrosion problems. The annular pressure caused by tubing leakage is characterized by high pressure and rapid rise rate, resulting in wellhead jacking, gas leakage, and wellbore structure corrosion, which has become the main cause of wellbore integrity failure in offshore gas wells. Therefore, a model of heat and mass transfer and distribution in offshore gas wells was established firstly, and the physical process of gas leakage and accumulation was described based on the pinhole model and the principle of gas PVT characteristics and volume compatibility. The results show that the depth and equivalent size of the leakage point are two important factors affecting the pressure rise process and leakage rate. Taking case well parameters as an example, after inversion calculation, the annulus pressure in case well was 23.0 MPa, the leakage point equivalent diameter was 2.3 mm, the maximum leakage rate was 0.30 m3/min, and the wellbore safety risk is relatively high. Mechanical repair and chemical plugging agent are recommended to seal the tubing leakage. These risk assessment technologies provide reference for wellbore integrity design and management to reduce CO2 leakage risk caused by wellbore integrity failure.