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.