Applicability of Hot Water-Alternate- CO2 Flooding in Heavy Oil Reservoirs,
Increasing world energy demand and depletion of conventional oil reservoirs is forcing scientists and industry to seek new – unconventional – sources of hydrocarbons. While conventional crude oil accounts for 1.0 trillion barrels, the amount of heavy oil and bitumen is five times larger – 5.4 trillion barrels (Herron 2006). A huge part of these extremely high and difficult to extract hydrocarbons is deposited in Canada. In such heavy oil reservoirs, waterflooding has proved to be inefficient due to unfavourable mobility ratio between displacing and displaced fluids that leads to low sweep efficiency and early breakthrough. This results in high residual oil saturations. At the same time, in thin and shallow reservoirs, thermal enhanced oil recovery (EOR) methods are not economic. While 90% of Saskatchewan heavy oil still remains underground, there is a huge opportunity for development of new EOR techniques in this province. One of the proposed new methods is Hot Water-Alternate-CO2 technology. Alternative injection of water and carbon dioxide seems to give benefits of both water and gas flooding. A combination of hot water and CO2 injection shows good potential to improve the performance of current waterflooding projects in heavy oil reservoirs. The aim of this study was to investigate the performance of conventional EOR methods (i.e., continuous CO2 flooding, waterflooding, and WAG-CO2) in order to compare them to the newly proposed one – Hot WAG-CO2. The evaluation of these methods was performed based on the comparison of recovery factors (RF) from each experiment. Also, the effect of the sequence of water/gas injections on the total RF was studied. Three types of sandpacks and two oil samples from Saskatchewan heavy oil fields were used. Permeabilities and porosities for each sand system were 32 Darcy (D), 36%, 12 D, 38%, and 18 D, 34%. Viscosities of the oil samples were 5,712 mPa·s and 23,768 mPa·s at 25°C. All the floods were conducted at a pressure of 1.38 MPa (200 psi) and ambient temperature of 23°C. The experimental procedure consisted of vacuuming the sandpacks, measuring porosity, water saturation, absolute permeability, and oil saturation, flooding, and cleaning. Produced oil was collected in small increments and recovery curves as a function of pore volume (PV) of injected fluids were built. For the hot injections, temperature was recorded at the inlet and the outlet of the sandpack. Sequence of the injection fluids turned out to have an impact on the total recovery factor. Gas flooding prior to the waterflood had a beneficial effect on the oil recovery with an average increase in RF of about 5% of original oil in place (OOIP). Hot WAG-CO2 showed the best results among all experiments – recoveries were up by at least 10 %OOIP and the gas requirement was lower. The highest recoveries among all WAG experiments performed were observed at a fluid injection temperature of 30°C, injection rate of 0.1 cm3/min and gas/water slug ratio of 1:1.