Carbon Capture and Storage (CCS) is an effective method for reducing CO2 emissions by permanently storing captured CO2 underground. Depleted oil and gas fields are promising CCS targets due to their well-characterised nature. However, injecting high-pressure CO2 into low-pressure reservoirs can lead to hydrate formation due to Joule-Thomson (JT) cooling and phase changing during CO2 injection, potentially reducing injectivity.

Since hydrate formation mainly occurs in the near-wellbore, it is essential to assess the influence of mud filtrate and formation damage on CO2 hydrate formation. Oil-based mud (OBM) can invade the formation, making its filtrate the first material to interact with injected CO2. This study addressed the impact of the synthetic OBM filtrate, represented by dodecane, CaCl2-15wt%, and W/O emulsion, on CO2 hydrate formation in micromodel experiments, focusing on hydrate morphology and saturation.

Results show that the interaction between CO2 and synthetic OBM filtrate can induce CO2 hydrate formation under certain pressure-temperature conditions. Instability of the OBM filtrate emulsion during low-temperature CO2 injection, followed by water droplet coalescence, increases the water-CO2 contact area, thereby promoting hydrate formation. Experiments involving oil and W/O emulsion revealed a distinct hydrate morphology, with hydrates present not only at the CO2-water interface but also within the CO2 flow pathways.

The study also highlights that high salinity CaCl2–15wt% acts as a CO2 hydrate inhibitor. In the presence of synthetic OBM filtrate, hydrate saturation is higher than in the system containing only CaCl2–15wt% or a combination of CaCl2–15wt% and dodecane, likely due to enhanced water–CO2 contact from droplet coalescence in the W/O emulsion.

Furthermore, the impact of formation damage on near-wellbore pressure and temperature relative to the hydrate stability zone (HSZ) was examined. Mud filtrate can reduce permeability, while hydrate formation can exacerbate this damage. Such changes alter local thermodynamic conditions, requiring a coupled wellbore–reservoir simulation to capture the dynamic interactions.

Simulation results indicate that greater formation damage may reduce the risk of hydrate formation by increasing the temperature and pressure in the near-wellbore. If hydrate occurs and leads to additional permeability impairment, it could result in increased bottom-hole temperatures. Such a temperature rise may help dissociate the hydrates, provided the increase is sufficient to shift the system out of the HSZ. Formation damage due to mud filtrate (30-60% permeability reduction) typically keeps pressure and temperature conditions within the HSZ. Additional damage due to hydrate formation (80-90% permeability reduction) significantly increases bottom-hole pressure (BHP) and bottom-hole temperature (BHT), thus shifting the pressure and temperature conditions outside the HSZ. Notable changes in both BHP and BHT occur when the radius of the damaged zone increases from 0 to approximately 0.5 meters. Beyond this threshold, further increases in damaged radius result in only marginal BHP and BHT changes.

This thesis explores the occurrence of salt dry-out and hydrate formation when injecting CO2 into porous media. In large-scale CCS projects, injecting CO2 can potentially lead to salt precipitation or hydrate formation. These processes diminish injectivity and negatively alter reservoir rock properties. To gain deeper insight, experiments were conducted utilizing microfluidic setups, which allow for visual observation of salt-crystal or hydrate formation. Using microfluidic chips, ten salt dry-out experiments were conducted with varying pore sizes and six hydrate experiments were conducted with varying pulse trigger times. For the dry-out experiments, it was shown that salt crystals form mostly at the outlet side and that heterogeneity has a large impact on the precipitation process. A heterogeneous pattern results in a shift in salt distribution to the small pores, with results showing salt saturation at 7% in the small pore section of the medium-small pore chip, exceeding the 3% in the larger pore section. This shows the significant role of capillary action on salt precipitation. Results highlight that higher CO2 flow rates accelerate water evaporation and salt formation, yet final salt precipitation levels remain similar across varied flow rates. For instance, in the small pore size chip, final salt saturation was observed at 7% with a flow rate of 4.38 mm/s, decreasing to 4% at 0.78 mm/s. Additionally, the importance of high water saturation for salt dry-out and the impact of water backflow is shown. For hydrate formation, the importance of temperature and pressure was noted in these experiments. Three different pressure pulses were employed: manual control, a 0.5-second electronic pulse, and a 0.2-second electronic pulse, which all showing great effect on hydrate formation, yet no correlation could be determined between pulse length and hydrate saturation. Specifically, manual control yielded a 15% hydrate saturation with a 9.4% conversion factor, while the 0.5-second pulse achieved a 7% saturation and 9.1% conversion factor. The 0.2-second pulse resulted in 8% saturation and a 5.9% conversion factor. For the dissociation, the large effect of temperature was observed. All experiments showed a stable hydrate concentration, and a dissociation temperature between 5 and 9°C where temperature differences as small as 0.1°C were shown to be the difference between no dissociation and complete disappearance of all hydrates. Next to this kinetics, an interesting observation regarding the hydrate morphology was made. In addition to the five hydrate morphologies found in literature, a sixth, ‘sheet’-like type was observed.