As reservoir pressure drops during oil production and reaches the saturation, solution gas starts to liberate. In many cases, the liberated gas comes together and coalesce forming a mobile gas phase (gas cap). Since gas has a lower density than oil, this will support the reservoir pressure by an efficient gas-oil gravity drainage mechanism.
In other cases (as relevant to the present project), such as unfavourable pore size, pore/pore-throat aspect ratio, and capillary-forces/wettability balance, the liberated solution gas will not coalesce and stay in the form of disconnected gas bubbles.
This gas bubbles can block pore/throats and thereby lower the effective permeability of the reservoir. The stability/immobility of the individual gas bubbles is strongly affected by the pore/throat size and geometry and is a risk in tight/low permeability reservoirs. Further, reservoir wettability can have a governing effect on the mobility of the individual gas bubbles and thereby hinder the coalescence process.
The project’s objective is to utilize experimental data to correlate the change in the oil relative permeability with the amount of liberated gas, in case the gas stays in the core in the form of bubbles, and to develop a dynamic gas-oil relative permeability model if this gas is produced.
Main supervisor:
Alexander Shapiro
Co-supervisor:
Wei Yan