Y.P. Zhang

Laboratory Investigation of Enhanced Light-Oil Recovery By CO/Flue Gas Huff-n-Puff Process

This paper focuses on phase behaviour measurements with reservoir oil-CO 2 mixtures and on coreflooding tests in the huff-n-puff mode to characterize the system, determine the influential mechanisms, and supply data for simulation of the field implementation. The results indicate that significant amounts of CO 2 could dissolve in the oil, which caused oil swelling and viscosity reduction. During the puff cycle, the oil retained CO 2 preferentially to methane; thus, the beneficial swelling and viscosity effects were maintained over an extended portion of this cycle. Corefloods were performed to investigate the effect of waterflood residual oil saturation and injection gas composition (CO 2 and enriched flue gas) on oil recovery. Incremental oil recovery was observed to be sensitive to waterflood residual oil saturation and to the process application scheme. Coreflooding results suggest that the huff-n-puff process may be more suitable to oil-wet than water-wet reservoirs.

Determining the Most Profitable ASP Flood Strategy for Enhanced Oil Recovery

While chemical floods have proven technically successful, the high cost of chemicals makes it challenging to develop a cost-effective tertiary process. If high interfacial tension (IFT) exists between the oil and water phases, the resulting capillary forces will resist externally applied viscous forces. This could cause the injected water and chemicals to bypass the residual oil and go to waste. The experimental studies presented here include reservoir fluid characterization, IFT measurements, and coreflood tests; all critical elements in designing a cost-effective alkaline/surfactant/ polymer (ASP) injection strategy. Coreflood tests used either sandpacks or composite reservoir cores with a selected medium crude oil. Injected surfactant concentration, slug size, chasing fluid, and residual oil saturation were the varied parameters. The optimal surfactant concentration of 0.15 wt% and slug size of 0.5 pore volume (PV) obtained relatively high oil recovery while maintaining a favourably high displacement efficiency ratio. Incremental recovery was 23 - 41% initial oil-in-place (IOIP) in sandpack tests and about 16% IOIP with reservoir cores. Overall, these coreflood results indicate that ASP flooding is a suitable enhanced oil recovery method for medium oil if the right chemical concentration and slug size are selected.

Effect of HS and Pressure Depletion on the CO MMP of Zama Oils

Phase behaviour and minimum miscibility pressure measurements were carried out to evaluate the potential of applying miscible CO 2 /H 2 S flooding in the Zama reefs of NE Alberta, Canada. Since there is some variability in the properties of oils from different wells or reefs, the measurements were carried out on recombined reservoir fluids from two different wells. The injection solvent will be supplied from a nearby gas plant that is expected to produce CO 2 /H 2 S streams with a range of compositions due to a number of operational factors. Accordingly, three solvent injection gases were considered: pure CO 2 and CO 2 containing 20 and 40 mol% H 2 S. Minimum miscibility pressure (MMP) measurements were carried out using the rising bubble apparatus (RBA). The MMP decreased almost linearly with the amount of H 2 S in the injection gas in the range of compositions studied. Some evidence of precipitation of solids was observed. Measurements were also carried out to determine the CO 2 MMP of these reservoir fluids as they were depleted of gas through a differential liberation procedure. The results show that the MMP decreased with decreasing liberation pressure. Key properties of the liberated reservoir fluids were also measured and compared with those of the recombined reservoir fluids. The results show that miscible flooding with sour acid gas is feasible in this case, and could provide an excellent means of storing/sequestering these gases while improving oil recovery.

Experimental Investigation of Immiscible Gas Process Performance for Medium Oil

Immiscible CO 2 injection is a potentially viable method of enhanced oil recovery (EOR) for medium oil reservoirs in south-western Saskatchewan. The relatively high reservoir pressures could result in a large extent of CO 2 dissolution, significant oil viscosity reduction and oil swelling. Laboratory corefloods were used to compare the performance of different modes of CO 2 injection into a medium-gravity oil system. The following methods were compared: injection of a single CO 2 slug chased by water, simultaneous injection of water/CO 2 , and different water-alternating-gas (WAG) cycles. The results indicate that both a single CO 2 slug and the first WAG cycle in a series produced oil very efficiently, possibly owing to good gas/oil contact at the relatively high residual oil saturation at this stage. The simultaneous injection of water/ CO 2 was not as effective as a single CO 2 slug, possibly because the co-injected water shielded the oil from being contacted by the gas. Among the four runs, a coreflood with four WAG cycles recovered the most incremental oil—20.58% initial oil in place (IOIP)-while the co-injection process produced the least (8.91% IOIP). This experimental study suggests that the immiscible CO 2 EOR process is viable for medium oil reservoirs with relatively high pressures, and that proper process application is important for maximizing additional oil production.