The simulation of thermal recovery processes and their variations like non-condensable gases (NCG) co-injection with steam in SAGD require reliable gas-liquid relative permeability curves. In this work, three experiments were conducted to extract equivalent thermal relative permeability curves, and the experimental curves were used as an input in a numerical simulation model to evaluate the NCG co-injection with steam in SAGD. Heavy oil was diluted with toluene to mimic the viscosity of the oil at 165, 195, and 225°C. It was assumed that the viscosity variation was the main factor affecting the temperature-dependent gas-liquid relative permeability curves. Athabasca sand was packed, and after water and oil were flooded, gas was injected. Three sets of gas-liquid relative permeability curves were extracted through history match. The experimental curves were used as an input in a simulation model to evaluate the effect of the amount of NCG and time of NCG co-injection in SAGD using CMG STARS.
In contrast to previous simulation studies, the current simulation results showed that most of the injected gas leaked from the steam chamber and accumulated at the top of the reservoir. Part of the gas stayed at the top of the steam chamber insulating the steam chamber from the overburden rock. The gas that leaked from the steam chamber aided in additional recovery of oil. According to the simulation results, for a homogeneous reservoir, small amounts of NCG (about 1 mole %) can be co-injected with steam at any time of a SAGD project to reduce its energy requirements without a negative impact in the oil recovery. This amount can be progressively increased to further reduce the energy requirements and increase the ultimate oil recovery. With the introduction of the new experimental gas-liquid relative permeability curves, it would be possible to optimize NCG co-injection processes in SAGD with the use of numerical simulation, taking into account the flow behaviour of gases in the reservoir that usually is not considered.