CO2 flooding is a widely employed method for enhancing oil recovery. However, it faces challenges stemming from differences in viscosity and density between oil and CO2, leading to poor sweep efficiency. This can result in issues such as viscous fingering, channelling, and gravity segregation, causing premature breakthroughs and excessive gas production. To address these concerns, the Polymer Assisted Water Alternating Gas (PA-WAG) technique combines the advantageous attributes of CO2 flooding, such as solubility and displacement, with the effective mobility control provided by polymer flooding. This results in a chemically enhanced Water Alternating Gas (WAG) flooding approach. A study by van Wieren et al. (2022) delved into the effectiveness of PA-WAG in addressing CO2 flow challenges and improving sweep efficiency by conducting core-flood experiments. This work builds upon that study by employing numerical simulations to replicate the core-flood experiments. These simulations shed light on the fundamental physical mechanisms during the PA-WAG injection process while also facilitating the calibration of flow parameters for practical implementation on a larger scale. The primary goal of this study was to comprehensively model three distinct enhanced oil recovery (EOR) techniques: polymer injection, CO2 flooding, and PA-WAG, all applied specifically to the Bentheimer sandstone cores. The objective was to history-match CT (Computed Tomography) scan saturation data, observed pressure drops, and oil recovery. A 2-dimensional (2D) model was constructed for each experiment, with CT scan images used to allocate varying porosity and permeability values to individual grid blocks. This enabled monitoring saturation distributions from the initial primary drainage phase onward. In the history matching of the primary drainage phase, parameters for relative permeabilities were determined from the Brooks-Corey equation, leveraging CT scan saturation data. The scaling of relative permeabilities based on CT scan saturations effectively accounted for capillary end effects observed in the core-flood experiments. During the history-matching of the polymer injection process, it was demonstrated that polymer-specific parameters, as determined from experimental data, could effectively modify waterflood relative permeabilities, thereby reducing the mobility ratio and accurately capturing the advancement of the polymer front. The formation of emulsions towards the end of polymer injection led to a notable increase in pressure drop, necessitating the incorporation of a high Residual Resistance Factor (RRF) to accommodate permeability reduction. In the case of history-matching for the CO2 flood, the black oil model successfully replicated the process of immiscible gas injection. It aptly captured gravity segregation while utilising CT scan saturation scaled relative permeabilities to assess the impact on oil recovery. The study unveiled that the relative permeability of gas under immiscible conditions was relatively lower than in miscible and near-miscible conditions. Simulating the PA-WAG injection by combining polymer and CO2 models effectively reproduced the core-flood experiments. The study substantiated the role of gas trapping in reducing the relative permeability of gas as a function of injection time, consequently leading to heightened pressure drops during subsequent polymer slug injections. The study showcased the efficacy of integrating black oil models for polymer and CO2 injection to successfully simulate PA-WAG injection and achieve unity with core-flood experiments yielding valuable insights into the physical processes underlying the technique.

Polymer flooding plays an essential role in Enhanced Oil Recovery by means of achieving a more favorable mobility ratio through increasing the viscosity of the displacing phase and thus improve macroscopic sweep efficiency. Conventional polymer, e.g., hydrolyzed polyacrylamide, dissolved in brine at high-salinity and high-temperature can be subjected to thermal degradation due to hydrolysis of amide group to acid which can result in precipitation driven by the interaction between acid groups and divalent ions, so these processes lead to loss in viscosifying power of drive fluid, thereby hindering polymer efficiency. To overcome these challenges associated with polymers at harsh conditions, a new hybrid dispersion consists of silica nanoparticles and hydrophobically modified polyacrylamide was proposed. This study aims to investigate the adsorptive and transport behaviour for this novel combination using rheological measurement and core flood experiments. Two-phase experiments were conducted to reveal the potential ability of the dispersion in increasing oil recovery compared to water flooding. Three different systems are used in this study, first, polymer solution at a concentration of 500 mg/L, second, nanofluids containing only SiO2 particles with a concentration of 5,000 mg/L and the third system is the dispersion of silica nanoparticles at 5,000 mg/L and PAM-98 at 500 mg/L. Rheological tests and single-phase experiment results showed that introducing silica nanoparticles to polymer solution led to the bulk viscosity enhancement and improvement in the adsorptive and transport behaviour of nanofluid. However, two-phase experimental results showed no increase in incremental oil recovery at the given study conditions, since water flooding was highly efficient.

Synthetic polymers, in the emulsified form, have been utilized for enhanced oil recovery applications by using saline make-up water. However, there are concerns that have been raised about their injectivity. The large entangled polymer chains can clog the pore throats, giving a tendency to cause injectivity reduction. In this study, processing techniques were used to condition an acrylamide-based copolymer inverse emulsion system at a salinity of 50,000 ppm TDS before being injected into porous media. The investigated polymer solution contained 4,000 ppm active emulsion-polymer and 2,400 ppm surfactant, providing a zero-shear rate viscosity of 13 mPas. Shearing with two agitators, a disperser and Ultra-Turrax, at different intensities and pressure-driven flow into a thin capillary reduces the size of the largest polymer and disentangles the polymer chains while maintaining its viscosifying power as much as possible. Subsequently, the filtration ratios (퐹푅) with optimum between 1–1.2 were determined by performing filtration tests in a 1-micron polycarbonate membrane to evaluate the plugging behavior. This was followed by sand-pack flooding tests of differently sheared solutions in order to investigate the impact of pre-conditioning on injectivity.
Bulk experiments enabled the establishment of master curves showing viscosity and screen factor dependences on accumulated energy during pre-shearing, regardless of shear origin. The injected unsheared polymer solution has an 퐹푅 of 1.6 and an injectivity gradient, e.g. ratio of resistance factor over 10 pore volumes, of 2.4. All injected pre-conditioned solutions have an 퐹푅 in the optimal range between 1 to 1.2. By imposing 15 MJ/m3, the disperser-sheared solution improves the injectivity by decreasing the injectivity gradient to 1.3, while the viscosifying power is reduced by 2% and the screen factor by 30%. To reach the same injectivity gradient of 1.3 with Ultra-Turrax, 31 MJ/m3 were imposed, which reduces the viscosity and screen factor by 11% and 44% respectively. The sheared solution into a capillary imposes 50 MJ/m3, giving an injectivity gradient of 2.7. Both viscosity and screen factor are reduced by 19% and 53% respectively. This indicates that the injectivity performance is shear-origin dependent and the resulting polymer structure, when sheared through contractions, has a different alignment as compared to shearing with the agitators, the disperser and Ultra-Turrax.
In conclusion, the rheological dependencies of sheared polymer solutions form a master curve dependent of accumulated energy during shearing with different shearing devices. Further, the proven beneficial impact of pre-conditioning with agitators before injection enables a better utilization of polymer flooding operations by reducing the risk of pore plugging.