CO₂ flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO₂ mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug. The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO₂ at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO₂, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores. Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO₂ injection. Continuous injection of CO₂ led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO₂ displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO₂ and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO₂). The addition of the polymer to the aqueous phase delayed both the water and CO₂ breakthrough (0.51 PV for water and 0.35 PV for CO₂). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO₂ breakthrough during PA-WAG injection as was evident from in-situ visualization. This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.

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Due to increased energy demand, it is vital to enhance the recovery from existing oilfields. Polymer flooding is the most frequently used chemical enhanced oil recovery (cEOR) method in field applications that increases the oil sweep and displacement efficiencies. In recent years, there has been growing interest to assess the use of polymer flooding in an increasing number of field applications. This is due to the improved properties of polymers at high-salinity and high-temperature conditions and an increased understanding of the transport mechanisms of water-soluble polymers in porous media. In this review, we present an overview of the latest research into the application of polymers for cEOR, including mechanisms of oil recovery improvement and transport mechanisms in porous media. We focus on the recent advances that have been made to develop polymers that are suitable for high-salinity and high-temperature conditions and shed light on new insights into the flow of water-soluble polymers in porous media. We observed that the viscoelastic behavior of polymers in porous media (e.g., shear thickening and elastic turbulence) is the most recently debated polymer flow mechanism in cEOR applications. Moreover, advanced water-soluble polymers, including hydrophobically modified polymers and salt- and temperature-tolerant modified polyacrylamides, have shown promising results at high-salinity and high-temperature conditions@en

We examine the role of preshearing on the flow properties of polymer solutions containing essentially an acrylamide-based copolymer obtained from an emulsified polymer emulsion inverted by a surfactant. The polymer solutions were presheared using three methods: (1) a Buddeberg disperser, (2) an Ultra-Turrax disperser, and (3) pressure-driven flow through a capillary. Shearing the polymer solution was done under fast flow to induce high stretching of the polymer chains and thus promote the break-up of the longest ones (i.e., decrease in relaxation time and shear-thinning level). The unsheared and presheared polymer solutions were forced through sand packs to compare their corresponding flow resistances. We observed that the reduction in the viscosity and screen factor of the presheared polymer solutions is path independent regardless of the shearing device. We found a critical Weissenberg number (Wi_c ∼ 13) above which the viscosity of the polymer solutions started to decrease. The resistance factor for the polymer solutions presheared with the Ultra-Turrax disperser at an energy input of 31.3 and 290.7 MJ/m³ was nearly 3 and 7 times, respectively, lower than for the unsheared polymer solution, while the viscosity decreased only by 27 and 48%, respectively. The sand-pack experiments were successfully interpreted using a numerical model taking into account time-dependent retention. The model showed that the flow of the presheared polymer solutions through the sand packs was enhanced mainly due to the breaking of the longest polymer chains, which results in smaller mechanical entrapment. This preshearing of the water-soluble polymers can be used in multiple industrial applications, including chemical enhanced oil recovery and optimization of polymer processing.

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Polymer flooding is a commercially viable chemical enhanced oil recovery (cEOR) method. It includes the injection of water-soluble polymers into a reservoir to improve the drive water viscosity and consequently to increase the sweep and displacement efficiency of the water. Despite the success in both laboratory and field applications, there are still some challenges associated with the application of polymers for cEOR. The first challenge is that the implementation of conventional polymers used for cEOR at high salinity, hardness, and temperature reservoirs is difficult and costly because of the viscosity loss and polymer precipitation at these harsh conditions. The second challenge concerns the injectivity of the polymers. Long polymer chains tend to block the small pores which leads to a time-dependent injectivity decline. This thesis investigates the potential solutions to address these two challenges in order to improve the performance of water-soluble polymers.@en

We investigate the effect of pH on external hematite colloidal particles entrapment and remobilization by core-flood experiments combined with X ray computed tomography. Suspensions of calibrated hematite colloidal particles were injected into Bentheimer sandstones sample, composed mainly of well-sorted quartz and small clay fraction (up to 1 wt%), consisting mainly of kaolinite. We have found that permeability impairment due to an external cake build-up can be reversed when pH exceeds the point of zero charge of hematite particles. This effect could be successfully interpreted by the switching of the surface charge of hematite particles from positive to the negative, similar to the rock surface. The experimentally verified pH-controlled electrostatic retention and remobilization technique can be extended to other colloidal particles, having pH-dependent surface charge, including natural clay minerals in hydrocarbon and geothermal reservoirs. Therefore, varying pH of injected fluid can be applied for targeted external cake build-up and transportation of colloidal particles within a reservoir.

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Water-soluble polyacrylamides have often been used to modify flow response in various water-based technologies and industrial processes, including paints, water treatment, paper manufacturing, and chemical enhanced oil recovery. Polymers are susceptible to degradation at combined high salinity and elevated temperature conditions which limits their overall performance. Hybrid mixtures of hydrophobically modified polyacrylamide (HMPAM) with hydrophobically modified silica nanoparticles (NPs) emerged as a promising strategy for achieving enhanced stability and high viscosity in brines having a high total dissolved solids (TDS) content and high hardness at elevated temperatures (>20 wt% TDS, including >1.5 wt% divalent cations at T > 70 °C). The rheological response of the hybrids at various concentrations of HMPAM and NPs was examined to investigate the synergic effects. Hybridization of HMPAM with NPs led to a higher viscosity at high salinity and elevated temperature. The viscosity improvement was more pronounced when the concentration of HMPAM was in the semi-dilute regime and concentration of NPs was higher than a critical threshold where the viscosity increased roughly by a factor of 1.5. Here we present the mechanisms of improved viscosity behaviour. The rheological data suggest the role of NPs in the bridging between HMPAM molecules, which in turn increases the hydrodynamic radius and consequently the viscosity of the hybrids.@en

Synthetic high molecular weight polymers have been utilized for enhanced oil recovery applications. Improving their injectivity remains an important issue for field applications. Large entangled polymer chains can clog pore throats, leading to injectivity decline. We investigated an emulsion polymer system and have developed a series of processing techniques to condition an acrylamide-based copolymer inverse emulsion system at a salinity of 50,000 ppm TDS before injection into porous media. The investigated polymer solution contained 4,000 ppm active emulsion polymer and 2,400 ppm inverter surfactant. The un-conditioned polymer system and test conditions were chosen to clearly demonstrate the impact of processing techniques on the injectivity behavior. The polymer solution was sheared with two agitators, a disperser and Ultra-Turrax, at different intensities and with a pressure-driven flow into a thin capillary to reduce the size of the largest polymer chains and disentangle the polymer chains while maintaining its viscosifying power. The injectivity of such differently sheared solutions was evaluated by performing filtration tests using a 1-micron membrane and sand-pack flooding tests. Our experiments have established a master curve showing viscosity and screen factor dependences on accumulated energy during pre-shearing, regardless of the mode of shearing. The un-sheared polymer solution had an unfavorable behavior in filtration test and sand-pack flooding experiment. After pre-shearing, the filtration behavior of polymer solution and the injectivity in sand-packs improved significantly. Polymer solutions sheared with a disperser at an energy input of 15 MJ/m3 improved the injectivity gradient (e.g. the ratio of the resistance factor over 30 pore volumes injected) from 3.7 to 1.6, while the viscosifying power was reduced by only 2%. To reach the same injectivity improvement with Ultra-Turrax, an energy input of 31 MJ/m³ were required, which reduced the viscosity by 11%. Shearing the solution using a capillary at an energy input of 50 MJ/m³, did not reduce the injectivity gradient while viscosity was reduced by 19%. 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.

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Alkaline Surfactant Polymer (ASP) flooding is a chemical EOR method to increase oil recovery after water flooding through IFT reduction and increasing sweep efficiency. Previous studies have shown that maximal oil recovery is reached when ASP flooding is performed at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase but a recently series of core-flood experiments indicated that comparable oil recovery could be obtained at under-optimum salinity conditions (Battistutta et al. 2015). Mechanistic simulation of ASP flooding considering phase behavior of water-oil-surfactant system, geochemical reactions and alkaline consumption is needed to validate the experimental data and provide a robust model for field scale studies. In this paper detailed history matching of series of core-flood experiments was attempted. Experiments were performed at different salinity conditions (optimum vs. under-optimum) and with different core types (Bentheimer and Berea) using a single olefin sulfonate (IOS) and crude oil with very low acid number (<0.05 mg KOH/g oil). The numerical simulations were performed using UTCHEM, multiphase multi-component simulator along with EQBATCH module to model the geochemical reactions. Neglecting the effect of in-situ surfactant (soap) generation, since the acid number of crude oil was low, modeling of the phase behavior showed an excellent match against experimental data and optimal salinity was observed at 2.0 wt% NaCl (+ 2.0 wt% Na₂CO₃).Using this and considering aqueous and cation exchange as the most important geochemical reactions in alkaline propagation, several ASP core-flood experiments at optimum vs. under-optimum salinity conditions were successfully modeled. An excellent matching of all the measured parameters including oil cut and recovery, pressure drop, pH and carbonate, alkali and surfactant concentration at effluent was also achieved. Modeling confirms the results obtained from experiment which regardless of core type, although minimum achieved IFT at optimum salinity conditions is lower than the one achieved at under-optimum conditions, comparable final oil recovery was observed for both cases. This emphasizes the importance of performing ASP flooding at under-optimum salinity conditions due to lower surfactant retention and reducing the likelihood of achieving over-optimum salinity conditions. In this paper a robust model which is calibrated with experimental data is presented to simulate ASP flood process at various conditions and the basic model can be used to perform further simulations and can provide practical and convenient approach to model field applications of ASP flooding.

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