Enhanced Oil Recovery by carbonated water injection (CWI) has recently attracted significant attention. The main advantage of CWI, compared to conventional CO2 flood, is that it requires small amount of CO2 and it can be readily applied to oil fields with on-going or planned waterflood. The challenge with CWI is numerical simulation of the complex compositional changes that take place as a consequence of the transfer of CO2 from CO2-enriched (carbonated) water to crude oil under reservoir conditions. We have recently reported that these compositional changes result in the formation of a new gaseous phase within the oil and become the dominant mechanism controlling the performance of CWI.

In this investigation, utilising the results of novel direct visualisation experiments, a new and improved methodology for simulating the performance of CWI has been successfully developed that is capable of reproducing the physical processes observed in our micromodel and coreflood experiments. First, the parameters controlling the phase behaviour of crude oil and carbonated water were identified and an equation-of-state (EOS) was tuned to simulate the partitioning of CO2 between the aqueous phase and the crude oil. Furthermore, to properly account for the formation of the new phase during CWI, three-phase flow functions and kr were utilised for simulation of flow. Using an integrated automatic-history matching algorithm, the proposed methodology is then employed to examine the capability of commercial reservoir simulators to couple mass transfer and multi-phase flow during CWI. For this, the results of a series of consistent coreflood experiments were used where carbonated water was injected in secondary and tertiary modes.

The results of the history-matching exercises demonstrated that, to properly capture the underlying mechanisms of EOR by CWI, the phase behaviour and three-phase flow functions should be coupled in numerical simulation of the process. The results also revealed that the binary interaction coefficients between oil components and CO2 would control the extent of the gaseous-phase formation. Also, a relatively high value for critical gas saturation was obtained to history match the coreflood experiments, which was in agreement with the results of the direct visualisations experiments. Moreover, a variety of three-phase oil relative permeability functions were considered to replicate the movement of the gaseous-phase, which would be dictated by reconnection of the oil ganglia. The new phase formation outperforms other oil recovery mechanisms such as reduction of oil viscosity and oil swelling.

The results of the study help improve the accuracy of the numerical simulation of the oil recovery processes involving CO2 and carbonated water injection. This will in turn improve the quality of our reservoir performance predictions and the reliability of our economic calculations of these enhanced oil recovery techniques.

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