Sealing Failure Mechanism and Integrity Evolution of the Formation–Cement–Casing System under CO2 Geological Storage Conditions

Carbon dioxide geological storage, as a fundamental element of the carbon capture, utilization, and storage (CCUS) technology framework, plays a pivotal role in achieving carbon neutrality. The long-term safety and storage efficiency are critically dependent on the integrity of the wellbore system. However, under high-temperature and high-pressure conditions, CO2 may react with wellbore materials, including cement, casing, and formation rock, which could result in material degradation, interfacial failure, and a reduction in sealing integrity, thereby posing a potential risk of CO2 leakage. Currently, research on the synergistic corrosion behavior of multimaterial systems in actual storage environments remains limited, particularly regarding the corrosion mechanisms and long-term evolutionary patterns under coupled temperature and pressure conditions, which warrant further investigation. This study innovatively fabricated plunger samples representative of the formation–cement–casing system to simulate the CO2 corrosion environment under varying temperature conditions (40°C, 60°C, and 80°C), pressure levels (4, 8, and 12 MPa), and exposure durations (7 and 14 days). The experiment employed a customized high-temperature and high-pressure reaction system, coupled with high-resolution X-ray computed tomography (CT) and digital image processing techniques, to systematically investigate the corrosion behavior and microstructural evolution of the cement sheath, formation rock, wellbore casing, and their multimaterial interfaces, specifically, the first interface (cement–casing) and the second interface (cement–formation). The results indicated that CO2-induced corrosion in the wellbore system exhibits significant coupling effects between temperature and pressure, along with time-dependent accumulation characteristics. Under high-temperature and high-pressure conditions (80°C and 12 MPa), the cement sheath undergoes moltenlike degradation. In addition, a multilevel pore structure consisting of dissolution cavities, primary flow channels, branched pathways, and micropores was formed within the reservoir rock, resulting in a significant increase in porosity from an initial value of 8% to 29%. Furthermore, characteristic morphologies, such as corrosion canyons and erosion fault zones, were observed in the interface region. Additionally, the casing material demonstrated distinct localized corrosion behavior in a supercritical CO2 environment. Quantitative analysis of CT images indicated that corrosion depth, porosity, and permeability increase significantly under elevated temperature and pressure conditions. Furthermore, the corrosion process exhibited distinct phase characteristics: the initial 0–7 days represent a rapid corrosion phase, followed by a deceleration and stabilization phase from 7 to 14 days. This study proposes a quantitative evaluation method for wellbore material corrosion based on CT technology, thereby elucidating the failure mechanism of the wellbore system under multifield coupling conditions. The findings establish a robust experimental basis and provide comprehensive theoretical support for material selection, integrity evaluation, and long-term safety assessment of CO2 storage wellbore systems. The research findings exhibit significant scientific merit and practical engineering implications, thereby providing valuable guidance for CCUS engineering applications and supporting the formulation of wellbore integrity management strategies.