One of the major challenges envisaged in the application of WAG in multilayered reservoir with large thickness is poor conformance of injectants. Critical premises in the success of any enhanced oil recovery flooding operation is that mobile oil volume should be increased and this increased volume is contacted by driving fluids to enable it to be produced from the producers. This oil volume should not be by-passed by the EOR injectant fluid. Another important aspect is that driving fluids and fluid front of mobilized oil needs to flow more or less equally throughout the reservoir. This happens when reservoir conformance is well addressed. Therefore, controlling the flood front in WAG injection is a major challenge in the success of immiscible WAG injection. This paper presents laboratory research, lab and pilot design modeling study for developing the suitability of foam for a challenging reservoir. Foam was generated by simultaneous injection of CO2 rich injection gas with selected surfactant formulation initially saturated with surfactant. Effect of series of injection rates were investigated as main parameters for foam propagation and stability under field condition. It was observed that mobility reduction factor (MRF) increases with increasing flow rates and stabilized when the flow rates were decreased. The effects of multiple injections at fixed flow rates and from low to high rates through Surfactant Alternating Gas (SAG) were compared. SAG at low rates not adequate in generating strong foam thus produced very low MRF. SAG at multiple small slugs from low to high rates generated high MRF caused by frequent contact and mixing between surfactant and gas. Co injection and multiple injection through SAG indicated moderate MRF are obtained at high flow rates as in the near wellbore area and high MRF ensuring good mobility control and sweep efficiency when foam propagates within the reservoir.

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and with the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here we present a novel but relatively simple experimental technique for investigating the effect of oil on pregenerated foam in porous media. This allows one to compare the effects of oil on pre-generated foam and on foam generation without the experimental complications involved in using two separate porous media. We coinject surfactant solution and gas into a relative narrow core (1 cm diameter), and inject oil into the core some distance downstream from the inlet through ports in the side of the core. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam in a porous medium much larger than pore dimensions. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. We illustrate the technique with a study of the effect of one crude oil with two surfactants. With this system, there is a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experiences a more-significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 15 cm, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.