Flow Assurance Challenges of Well Design for CO2 Injection into a Depleted Gas Reservoir in Southeast Asia

Abstract A detailed steady state and transient flow assurance analyses were performed for nine CO2 injection wells, to store the captured CO2 from Lang-Lebah field's processing plants into depleted Golok gas reservoir. The challenges with Joule-Thomson (JT) cooling effect in early life injection with low reservoir pressures were assessed. This work outlined key technical aspects of well stress analysis, defining operating envelope, operating procedures for upset transient operations and guides for material selection and cement preparation. The impact of impurities in captured CO2 was analysed on the selection of EoS, phase envelope, hydrate risk and dry ice formation. The impact of process impurities, e.g., glycols, were compared against available experimental data. Nitrogen was used to dry-out the CO2 pipeline during pre-commissioning. Therefore, impact of N2 concentrations in CO2-rich mixture on JT cooling were evaluated with various EoSs during initial start-up operation and were compared to experimental data. The steady state and transient analyses were assessed using rigorous OLGA well feature with compositional tracking module to ensure encountering the impact of CO2 impurities on well design. The initial start-up operation with low reservoir pressure were simulated. To minimize JT cooling, it is proposed that well needs to be bullheaded to base-oil plus a nitrogen cushion with minimum 22 bar pressure prior to injection. The impact of nitrogen concentration on JT cooling depends on the fluid phase during injection. As expected, extra JT cooling was observed with dense phase injection compared to gas phase. During normal operation in early life, the maximum flowrate required to be limited to avoid hydrate formation risk at bottomhole due to JT cooling across both choke and tubing. The analysis of shutdown and restart operations during early and late life of injection shows manageable JT cooling at wellhead. The lowest temperatures at topside and in DHSV were observed in well blow-out scenario, which associated with hydrate and dry ice formation risks. The routine DHSV testing through bleed-off operation on topside were assessed during early and late life of injection. The required time for depressurisation and boiling-off of CO2, the peak rate and minimum temperatures at wellhead, topside and downhole safety valve were reported. Novelty of this work are: (1) The comparison of fluid modelling tools and EoSs in industry with the experimental data, (2) Challenges with injection of CO2 into a depleted gas reservoir with initial low pressure were assessed, (3) Impact of using Nitrogen for drying CO2 pipeline in pre-commissioning on first CO2 injection and JT cooling were analyzed. The JT cooling during injection were compared against experimental data. (4) The limitations of using conventional oil and gas design tools for CCUS application were discussed.