Assessing the feasibility of CO2 storage in a depleted gas field

Republic of Korea, Asia, Offshore

Utilizing a depleted gas reservoir in the East Sea of offshore Korea, Korea National Oil Corporation (KNOC) initiated the nation’s first large-scale carbon capture and storage (CCS) demonstration project. The maximum injection rate of the project is up to 1.2 million metric tons of CO2 per annum. To assess the potential for storage, SLB was engaged to conduct a feasibility study. Leveraging a comprehensive, integrated study workflow, SLB was able to model and simulate several injection plans. The study showed that CO2 injection operations can be achieved without the risk of CO2 leakage or fault activation as well as the damage to the formations and well integrity.

First discovered in 1998, the Donghae-1 gas field started its production of gas and condensate in 2004, placing South Korea among the global hydrocarbon producers. The field stopped producing in 2021, making it a prime candidate for geological CO2 sequestration. In an effort to assess the injectivity, containment, and long-term sustainability of the site, an integrated workflow with geomechanical modeling was vital to evaluate and address these factors.

To evaluate the integrity of CO2 storage in Donghae-1 gas field, SLB completed a thorough integrated study workflow comprised of three key technical components. The first was a geological model constructed to capture the structure and honor spatial heterogeneity. Second, geomechanical modeling was performed, consisting of core tests, as well as 1D and 3D mechanical earth modeling (MEM). This workflow is crucial to comprehend carbon storage capacity and formation integrity. It provides insights on the rock strength and initial stress state, which determines the formation's capability to resist injection-induced disturbance. It also forms the foundation for the next stage of simulation. Lastly, coupled reservoir geomechanics simulation was executed at two distinct scales. The aim of the analysis was to evaluate the potential of CO2 leakage that might occur during injection. To do this, both a full-field scale model and near-wellbore model were built to understand how the stresses and strain that the injection of CO2 might affect the reservoir and wellbore integrity, respectively. This simulation also aimed to determine related leakage risks during injection.

As a result of these efforts, two injection plans were deemed feasible from a geomechanical standpoint, as the stress path of the caprock and reservoir remained well below the Mohr-Coulomb failure envelope throughout the injection process and well integrity is maintained.

Technical details

For more information, read ARMA 23–536.

CO2 plume and spill point.
In this case, there was no limit of reservoir and borehole pressure. Therefore, the injected CO2 volume was much larger than the other cases, and the maximum reservoir pressure was up to 100 MPa. As a consequence, the overburden formation was uplifted by 1.4 m.
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