R.T. Okwen, Illinois State Geological Survey
J. F. Lea, Production & Lift Technology
One requirement of a Class VI Underground Injection Control permit involves continuous monitoring and reporting of injection pressure. Wells in pilot and commercial scale carbon dioxide (CO2) storage sites are equipped with devices that measure pressure and flow rate during injection operations. Downhole device failures have occured during CO2 injection operations in projects, which prevent bottom hole pressure measurement and require time consuming repairs. A model that can be used to accurately predict bottom hole pressures, based on tubing flow performance, during CO2 injection is warranted.
This paper uses a two-phase flow model, based on Hagedorn-Brown correlation that uses wellbore parameters and correlated CO2 properties to predict bottom hole pressures during injection. A finite-difference program that uses CO2 density and viscosity, wellhead temperature and pressure, bottom hole temperature, tubing diameter, roughness, well length, and injection rate as input to the model was developed for calculating vertical wellbore pressure changes during injection. Input parameters that have some effect on results are presented and discussed.
The program was applied to field injection data from the Illinois Basin Decatur Project and Industrial Carbon Capture and Sequestration projects to evaluate predicting measured bottom hole pressure data. The predictions matched measured bottom hole pressure within (average relative error).