This work introduces an efficient approach in addition to the traditional scheme of polymer screening for the application of enhanced oil recovery. Microfluidics technology which requires less sample volumes, and less time consumption, is applied to the polymer screening procedure. This approach delivers an efficient screening process and enables the upscaling of polymer flow behavior in porous media. This work investigates three commercial polymer products, A, B, and C, which vary in average molecular weight at shear rate (0.1 – 1000 s−1) and temperature (20°C– 60°C). Fifteen polymer solutions with different concentrations are made from the three products and screened through three evaluation stages. The first stage is measuring the bulk shear viscosity of the polymer solutions in the rheometer. The second stage is conducting single-phase polymer flooding through a novel micromodel. The stage of this approach applies the results from the earlier stages by running two-phase flooding experiments that implement polymer flooding for reservoir conditions of an oil field in Oman. The micromodel structure used in this work is generated based on X-ray micro-computed tomography (μCT) images of a Bentheimer core plug. Thus, the micromodel's porosity, permeability, pore, and grain size distribution are similar to the core plug. This characteristic gives an upscaling potential to a larger scale, such as core plug or even a field implementation. A database with bulk shear viscosity and model fits (Power law & Carreau) is generated from the rheometer measurements for polymers A, B, and C. A novel 3D surface model that relates the shear rate, temperature, bulk viscosity, and concentration is developed from the data in the first stage. The single-phase flooding experiments allow the investigation of the behavior of polymer in porous media under shear and extensional flow. Furthermore, the comparison of bulk shear viscosity and in-situ viscosity shows the potential to support the analysis of an empirical constant (C-factor). In addition, polymer injectivity and retention are investigated by analyzing the pressure drop and residual resistance factor after each single-phase polymer flooding experiment. The last stage of this work provides the improvement of displacement efficiency and the recovery factor, which measures the success of the approach. The novelty of this approach is the utilization of the linear Bentheimer micromodel for delivering an efficient polymer screening process. This micromodel reflects similar rock properties as Bentheimer rocks, which provide the potential to upscale the results from microfluidics to reservoir rocks. In addition, the novel 3D surface model developed in this work allows comprehensive screening, which is accomplished through combining the parameters required in polymer evaluation at one domain.

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.

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 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.

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.