Integrity of wellbores and near wellbore processes are crucial issues in geological carbon storage (GCS) projects as they both define the confinement and injectivity of CO₂. For the proper confinement of CO₂, any flow of CO₂ along the wellbore trajectory must be prevented using engineered barriers. The effect of cyclic stimuli on wellbore integrity, especially in the context of GCS projects, has been given less attention. In this study, the effect of pressure- and temperature-cycling on two types of wellbore composites (i.e., casing-cement and cement-caprock) have been investigated experimentally in small- and large-scale laboratory setups. The experiments have been carried out by measuring the effective permeability of the composites under pressure and thermal cyclic conditions. Furthermore, the permeability of individual samples (API class G and HMR+ cement and caprock) was measured and compared to the permeability of the composites. The results indicate that the permeability of API class G cement when exposed to CO₂ is in the order of 10⁻²⁰ m² (10⁻⁵ mD) as a result of the chemical reaction between the cement and CO₂. In addition, the tightness of the composite cement–rock has been confirmed, while the permeability of the composite casing–cement falls within the acceptable range for tight cement and the CO₂ flow was identified to occur through or close to the interface casing–cement. Results from thermal cycling within the range −9 to 14 °C revealed no significant effect on the integrity of the bond casing–cement. In contrast, pressure cycling experiments showed that the effective pressure has a larger influence on the permeability. The potential creation of micro-cracks under pressure variations may require some time for complete closing. In conclusion, the pressure and temperature cycling from this study did not violate the integrity of the casing–cement composite sample as the permeability remained low and within the acceptable range for wellbore cement.

Depleted hydrocarbon reservoirs (DHRs), particularly depleted gas reservoirs (DGRs), are increasingly regarded as promising candidates for geologic carbon storage (GCS). However, their low abandonment pressure poses significant thermo-hydraulic challenges during the injection of cold, high-pressure CO₂. In such non-isothermal conditions, complex processes may occur, including Joule–Thomson (J-T) cooling, hydrate formation, salt precipitation, and thermal fracturing, all of which may affect storage performance. This study presents an integrated assessment of the impact of CO₂ injection into DGRs on the three key pillars of GCS: capacity, injectivity, and containment. The analysis integrates laboratory experiments conducted at our institute, simplified analytics and numerical simulations to assess the governing physical mechanisms. The findings indicate that the cold CO₂ injection can enhance effective storage capacity during the injection phase. This is attributed to the increase in fluid density and the delay in pressure buildup. However, the post-injection thermal equilibrium may result in pressure rebound. The CO₂ injectivity has been demonstrated to be significantly impacted by the near-wellbore thermal effects. While thermo-induced fracturing may enhance injectivity, it poses potential risks to wellbore and caprock integrity. The process of hydrate formation depends on the local temperature and petrophysical conditions, with dynamic factors further reducing the likelihood of pore plugging. Salt precipitation has been found to be less critical under typical DGR conditions with low initial water saturation, although having the potential to become significant in the presence of water influx and/or cyclic injection. The findings provide a technical basis for enhancing the engineering design, accelerating the certification process, and ensuring the safe operation of future GCS projects in DGRs.