Unlocking CO2 Injection in Depleted Reservoirs: A Flow Assurance Modeling Approach for Carbon Capture and Storage

Abstract Carbon, Capture, and Storage (CCS) plays a pivotal role in unlocking production from sour gas fields. For a recent PTTEP greenfield development in Sarawak, Malaysia, hydrocarbon gas containing carbon dioxide (CO2) above 15 mol% must be treated to meet sale specifications. To develop the hydrocarbon resources with the least Greenhouse Gas (GHG) intensity, CO2 captured from gas production will need to be transported and injected offshore into depleted reservoirs. The behavior of CO2 up to the storage reservoirs must be extensively investigated to overcome challenges on corrosion, injectivity, and low temperature. A PVT analysis was originally done in the front-end design stage to define the phase envelope of the injected CO2 in relation to the contaminants from the gas treatment system. Subsequently, steady state and dynamic flow assurance assessments of the integrated CO2 transport and injection network were conducted to determine the safe operating window for the overall system. Key findings were then translated into functional design requirements for the CCS facilities such as the transport pipeline and injection platform. To mitigate hydrate risks at the well bottom-hole and keep CO2 along the transport pipeline and injection wellhead platform in supercritical phase, CO2 injection must closely adhere to the established pressure, temperature, and flow rate envelopes based on the flow assurance analysis. Once all storage reservoirs are sufficiently pressurized, the arrival temperature of CO2 at the injection platform no longer needs to be controlled which will allow CO2 to be injected at seabed temperature with no adverse risks in the wellbore. Several facility design options to achieve the desired CO2 injection pressure and temperature at the remote wellhead platform were then assessed resulting in the most cost-effective and energy-efficient decision to insulate the subsea transport pipeline. Dynamic flow assurance study results were also included to operating philosophies enabling the CO2 transport system to be started up and restarted even under the most onerous pipeline shut-in scenarios and environmental circumstances. For possible issues with trace impurities in the captured CO2, such as TEG, the fluid specifications at the inlet of the transport pipeline are tightly controlled and considered satisfactory in minimizing the severe corrosion risk in the downstream facilities. In developing this greenfield initiative with minimal GHG emission, understanding the flow behaviors along the transport and injection network is crucial to enable up to 2.0 MTPA of CO2 injection into depleted hydrocarbon reservoirs. The lessons learned from this project can be used as a starting framework for future developments to overcome similar obstacles associated with CO2 injection.