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Abstract
The increasing availability of the anthropogenic carbon dioxide (CO2) and the drives to reduce its concentration in the atmosphere has increased the interest in CO2 injection for improving the oil recovery in maturing oil reservoirs. Many of these reservoirs are being waterflooded to sustain the oil production. Instead of injecting plain water, injecting carbonated (CO2-enriched) water could bring additional oil recovery and added benefit of safe storage of CO2. In carbonated water injection (CWI), CO2 is dissolved in the injected brine prior to injection and then transported through the reservoir by the flood water. As a single phase, carbonated water mobility contrast with oil is more favourable than in the CO2 gas-oil system thus improves sweep efficiency and retards CO2 breakthrough. The slightly higher density of the carbonated water than the unadulterated water would induce the injected CO2 to slump towards the bottom of the reservoir, eliminating the risk of buoyancy-driven leakage thus securing storage.

This paper presents the results of an integrated experimental and numerical simulation study of tertiary CWI. A series of high pressure flow visualisation and coreflood experiments as well as compositional simulation have been carried out to evaluate the process. A North Sea crude oil and brine were used at a pressure typical of real reservoir conditions.

The visualisation experiments in high-pressure glass micromodels reveal that the oil swelling from CO2 diffusion into the oil and the subsequent oil viscosity reduction, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution are the main mechanisms of oil recovery by the tertiary CWI. There was also evidence of micromodel surface becoming more water wet that could also play a role in the oil recovery. The coreflood tests results clearly show that the post waterflood CWI could remobilize the remaining trapped oil in the watered-out core that leads to significant additional oil recovery. A very gradual (dissolved) CO2 breakthrough exhibited in this process is a significant advantage over the sudden CO2 breakthrough problem commonly faced in the conventional CO2 flooding. CWI is also highly potential as CO2 storage injection strategy as demonstrated by almost 50% of the total volume of CO2 injected (in carbonated water) was being stored at the end of the test. There is a challenge in simulating the physics of the CWI process using the commercially available reservoir simulators which will also be discussed.

Introduction
With the continued increase in the fossil fuels demand for many years to come (IEA, 2006), there is an inevitable undesired CO2 emission from the burning of the fossil fuels, which is believed to have contributed to the problem of global warming. One of the important, immediately available and technologically feasible strategies for achieving substantial reductions in anthropogenic CO2 emissions levels while enabling continued use of existing energy supply is the capture of this CO2 and its subsequent storage in geological formations such as deep saline aquifers, depleted oil and gas reservoirs and un-mineable coal beds (IPCC, 2007). Injection of CO2 into depleting oil reservoirs to improve oil recovery has been implemented in many reservoirs worldwide for more than 30 years particularly in the United States where abundant natural resources of CO2 is available (Oil & Gas Journal, 2008). In these conventional CO2 EOR projects, maximizing the oil recovery is the main objective while CO2 injection and sequestration are to be minimized as much as possible.