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.

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Application of gas injection to displace crude oil for pressure maintenance and improving oil recovery often suffer from severe viscous fingering and gravity override. As such, Water-Alternating-Gas (WAG) injection mode is usually promoted, in order to improve macroscopic and microscopic displacements. The improvement in oil recovery due to WAG injection is attributed to the contact of the unswept zones and modification of residual oil saturations, targeting the attic oil. Hysteretic effects which changes saturation paths, due to sequential injection of water and gas, additionally improve the recovery. The gas flow may, however, still develop preferential paths that bypass many unswept regions because of its inherent viscosity and density differences against water. Foam as gas mobility controller has been studied and introduced to enhance WAG displacement process. It acts as a blocking agent in high-permeability zones and diverts the gas flow to the other oil-trapped regions. Foam is a discontinuous phase which consists of liquid lamella and foam gas. Having intermediate behaviours between water and gas, its stability is strongly dependent on the component saturation, strength, size, gas quality etc. As a result, it poses a great challenge to simulate these complex mechanisms and behaviours, not to mention the pertaining effects in the porous media. At present, foam mechanisms are widely modelled via simple quasi-equilibrium approach using interpolation parameters, such as oil saturation, capillary number etc. to correlate the corresponding Mobility Reduction Factor (MRF). This paper presents the foam model results which intend to predict the foam injectivity at wellbore conditions, subsequently developing an injection proposal scheme for the field trial of EWAG process in Malaysia oilfields. In turn, the field trial results later will be history-matched, aiming to improve the prediction model for successive full-field modelling. The mechanistic modelling approach employed in this study takes into account of changes of lamella densities, allowing foam degradation and regeneration via stoichiometric reaction expressions. The mobility control is modelled throughinterpolation of relative permeability using foam gas concentration as interpolator andpermeability blockage in the presence of trapped lamella in solid form.

The venture into various unconventional hydrocarbon resources, such as heavy oil and oil sands, has been aggressively undertaken by industrial oil players to satisfy the ever-increasing world energy demand. Heavy oil captures the global attention due to the sheer size of its oil-in-place volume. However, its high-density and high-viscosity characteristics represent a great challenge in terms of recovery optimization. Reservoir modelling and simulation has been widely recognized as an important technique to evaluate recovery efficiency as a function of the reservoir conditions and the type of recovery process. In this paper, an extra heavy oil reservoir, the Oilfield Alpha, located in Venezuela is selected as the reservoir of interest. Conceptual models of extra heavy oil recovery, categorized into cold and thermal techniques, are addressed. Both of the thermal methods (Steam Flooding, Cyclic Steam Stimulation, Steam Assisted Gravity Drainage, etc.) and cold methods (Horizontal Well, Vapour Extraction, etc.) are studied and modelled using CMG STARS simulator. Performance indicators - typically the recovery factor, oil production rate, Steam-Oil-Ratio (SOR), etc. - for each model are evaluated and compared. The simulation results show that, after 20 years of production, the thermal methods have prevalently higher oil recovery factor, i.e. 7 - 37 % of OOIP compared to that of cold methods, i.e. 8 - 13 % of OOIP. In conclusion, the mechanistic models assist in strategic reservoir development planning at preliminary stage and, in turn, provide enhancement of oil recovery and productivity.

Poor conformance and unfavourable mobility ratio in the reservoir are common issues that hinder effective oil production and recovery. These issues are often exacerbated when the displacement is associated with viscous oil driven by water in highly permeable porous media. One of the reservoirs located onshore in East Africa suffers from this issue of high bypassed oil due to the presence of viscous oil, i.e. viscosity of 20 cP and API gravity of 28°. Most of the produced wells were observed to experience early water breakthrough and suffered from high water cut at present. In view of this phenomenon, Alkaline-Surfactant-Polymer (ASP) flooding was proposed to recover the remaining oil that is bypassed and trapped underneath. Through laboratory evaluation, the main objective of this study was to generate an effective chemical concoction comprising of alkaline, polymer and surfactant which are compatible to the formation fluids and rocks for the targeted reservoirs. The laboratory works were conducted based on a comprehensive and systematic workflow. Sample characterization and fluid-fluid analysis at the early phase encompass the studies of phase behaviours, physico-chemical properties, thermal stability etc. These studies aimed to screen off the chemical candidates which did not fulfill the corresponding Key Performance Indicators (KPI). The successful ASP formulations were subsequently optimized in terms of their respective concentrations without sacrificing the technical performance. Fluid-rock analysis aimed to quantify the oil recovery potential and reduction of residual oil saturation through coreflood experiments. Due to the high Equivalent Alkane Carbon Number (EACN) of the crude oil, i.e. 19 (nonadecane), and ultra-low salinity of formation water, i.e. 950 ppm, the greatest technical challenge in this study was to identify an effective surfactant which could reduce the water-oil interfacial tension (IFT) significantly under the operating range. Despite the challenges, an optimized ASP formulation, with a concentration of 0.5 wt.% of alkali, 0.2 wt.% of surfactant and 0.2 wt.% of polymer, successfully fulfilled all of the required KPI. The coreflood results indicate a reduction of residual oil saturation more than 30 % of Oil-In-Place. With these encouraging laboratory results, it could lead to the prospect of pilot and detailed Field Development Plan (FDP) studies, which could further de-risk the chemical EOR projects in this region.