Polymer flooding most commonly uses partially hydrolyzed polyacrylamides (HPAM) injected to increase the declining oil production from mature fields. Apart from the improved mobility ratio, also the viscoelasticity-associated flow effects yield additional oil recovery. Viscoelasticity is defined as the ability of particular polymer solutions to behave as a solid and liquid simultaneously if certain flow conditions, e.g., shear rates, are present. The viscoelasticity related flow phenomena as well as their recovery mechanisms are not fully understood and, hence, require additional and more advanced research. Whereas literature reasonably agreed on the presence of these viscoelastic flow effects in porous media, there is a significant lack and discord regarding the viscoelasticity effects in oil recovery. This work combines the information encountered in the literature, private reports and field applications. Self-gathered laboratory data is used in this work to support or refuse observations. An extensive review is generated by combining experimental observations and field applications with critical insights of the authors. The focus of the work is to understand and clarify the claims associated with polymer viscoelasticity in oil recovery by improvement of sweep efficiency, oil ganglia mobilization by flow instabilities, among others.

The injection of sulfonated-modified water could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence, possible higher oil recovery in combination with polymer. Therefore, detailed experimental investigation and fluid-flow analysis into porous media are required to understand the possible recovery mechanisms taking place. This paper evaluates the potential influence of low-salt/sulfate-modified water injection in oil recovery using a cross-analyzed approach of coupled microfluidics data and core flooding experiments. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase micromodels and core floods experiments helped to define the behavior of different fluids. Overall, coupling microfluidics, with core flooding experiments, confirmed that fluid-fluid interfacial interaction and wettability alteration are both the key recovery mechanisms for modified-water/low-salt. Finally, a combination of sulfate-modified/low-salinity water, with polymer flood can lead to ~6% extra oil, compared to the combination of polymer flood with synthetic seawater (SSW). The results present an excellent way to make use of micromodels and core experiments as a supporting tool for EOR processes evaluations, assessing fluid-fluid and rock-fluid interactions.

This work aims to conduct, interpret and derive the multi-phase fluid flow behaviour more efficiently and feasibly from a novel perspective. The goal is to conduct a SCAL measurement using a microfluidic setup on a chip and interpret the in-situ results, where the parameters influencing the multi-phase fluid flow in porous media, such as wettability, capillary pressure, and relative permeability, are measured simultaneously. There are numerous economic and technical advantages of this approach. Conventionally, SCAL measurements are conducted through core samples using X-ray and multi-phase fluid flow parameters in porous media are measured separately. These properties can be simultaneously determined in digital rock physics (DRP) by applying micro-CT imaging but with high costs. The steady-state method was utilised in this study and re-designed for microfluidic flooding. The measurement was conducted using one oleic and one aqueous phase, applying different fractional flow steps, mimicking the range of varying water saturation in the reservoir during the depletion process. The used microchip has a synthetic pore-structure design with circular grain shapes. The measurements conducted are visible in real-time using a microfluidic approach. The experimental results show that it is possible to adapt the microfluidic flooding for conducting and interpreting SCAL measurements. An additional advantage of this method is that the wettability and capillary pressure could be successfully determined by means of image processing using only the data obtained from the steady-state method in a microchip. Since the measurements are visible live, and images of the microchip are captured with the desired frequency, the image processing facilitates the understanding and interpretation of multi-phase fluid flow in porous structures, which is not possible with cores. Overall, to overcome the technical and economic limitations of digital rock physics, the application of SCAL through microchips representing the porous media is a good alternative. The SCAL-on-Chip is a promising approach for describing and analysing multi-phase fluid flow. Image processing contributes to developing "smarter" and cheaper interpretation tools for estimating wettability and capillary pressure. It provides the possibility to derive mathematical models of the relationship between multi-phase flow characteristics. The derivation of a general function between the measured properties could be possible with machine learning and a sufficient amount of experiments using pore structures that closely resemble porous media.

The injection of Sulphonated-smart water (SW) could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence possible higher oil recovery in combination with the polymer. Therefore, detailed experimental investigation and fluid flow analysis through porous media are required to understand the possible recovery mechanisms. This paper evaluates the potential influence of Sulphonated/Polymer water injection in oil recovery by coupling microfluidics and core flooding experiments. The possible mechanisms are evaluated utilizing a combination of experiments and fluids. Initially, synthetic seawater (SSW) and Sulphonated-Smart water (SW) were optimized to be used in combination with a viscoelastic HPAM polymer. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase core floods and micromodels experiments helped to define the behavior of different fluids. The data obtained was cross-analyzed to draw conclusions on the process effect and performance. First, Sulphonated/polymer water solutions showed a slight decrease in the polymer shear viscosity as compared to the SSW-polymer. Similar behavior was also confirmed in the single-phase core flood-through the differential pressure, looking at the in-situ viscosity. Second, on the one hand, smart water produced only ~3% additional oil recovery as compare to the SSW through micromodel due to improved interfacial viscoelasticity, where no local wettability alteration was observed in the porous media. On the other hand, core flood experiments using SW led to ~12% additional oil as compare to SSW. This excessive extra recovery in core flood compare to micromodel could be due to the combined effect of interfacial viscoelasticity and wettability alteration. Micromodel is coat with a hydrophobic chemical; hence, wettability becomes hard to be altered through SW while in the core flood it is dominated with ionic exchange (local wettability alteration). Finally, a combination of SW with polymer flood can lead to ~6% extra oil as compare to the combination of polymer flood with SSW. Overall, coupling microfluidics with core flooding experiments confirmed that IFV and wettability alteration both are the key recovery mechanisms for SW. The evaluation confirmed that the main recovery mechanisms of smart-water injection are interfacial viscoelasticity and wettability alteration. Furthermore, it confirmed that the combination of SW with polymer flood could sweep the reservoir efficiently resulting in higher oil recovery. This topic has been addressed in the literature with mixed results encountered.

The properties of polymeric materials are commonly modified by adjusting the dispersity of the molecular weight distribution, since polymer properties are dominated by intermolecular interactions. We utilized this approach to alter the rheological behavior of polymer solutions for application sub-surface and other porous media flow. We correlate the molecular weight distributions with screen factor measurements and in-situ rheological behavior. Aqueous solutions were prepared using mixtures of partially hydrolyzed polyacrylamide (HPAM) having different molecular weights. The behaviour of the solutions was studied in single-phase flooding experiments using Bentheimer and Berea outcrops, as well as a glass-silicon-glass microfluidic device that mimics porous media. The in-situ rheological behavior determined from flooding experiments was monitored by differential pressure measurements. To improve data accuracy, the core flooding experimental set-up was equipped with multiple pressure sensors along the core. Polymer solutions of same shear viscosity but significantly different dispersities were utilized for the investigation. Elongational viscosities were determined by screen factor measurements. We show that the apparent viscosity during polymer injection is significantly altered for polymer solutions of same average molecular weight but different dispersity. Namely, the onset of shear thickening occurs at lower equivalent shear rates when dispersity is high. Furthermore, the flow of polymer solutions in porous media was correlated to screen factor measurements. This effect of the dispersity of the molecular weight distribution can be used to optimize polymer solution applications in porous materials.