Sustained Casing Pressure Assessment Based on Gas Leakage Rate by the State of Equation for Real Gas

Abstract

Gas leakage is one of the most concerning issues in wells for exploring conventional or unconventional oil and gas reservoirs, carbon sequestration, and geothermal energy. Wellbore barriers, such as tubing, casing, and cement, are the primary components that prevent the undesirable flow of subsurface fluids. However, due to the complexity of the operating condition in a harsh environment, the tubing integrity is prone to failure, causing gas leakage and forming a sustained casing pressure (SCP) at the wellhead. This work proposes a prediction model considering the real gas effect when evaluating SCP. The proposed model involves gas flow, leakage, and accumulation in the wellbore. With the pressure and temperature obtained by the flow equations as boundaries, the model estimates the gas flow rate at the leakage point and SCP. Subsequently, comparing the current leakage model with the conventional method demonstrates the model's performance. Finally, the current model is applied to an ultra-deep well to determine the leakage location by inversion. Further sensitivity studies reveal the influences of wellbore conditions on SCP, including the production rate, depth of liquid level, and annular fluid density. The study indicates that the traditional method based on ideal gas underestimates the mass flow rate by approximately 22% compared to the current model. When the adiabatic index of the conventional method is approximated as the isentropic coefficient, the mass flow rate may agree well with the current model. It is acceptable to predict the leakage flow rate by assuming that the production gas is pure methane and ignoring the influence of gas composition. The leakage position is the most influential factor for SCP. These results would help engineers predict SCP and determine the leakage location in wells.