Polymer Adsorption/Retention in Porous Media: Effects of Core Wettability and Residual Oil

Flow Behavior through Porous Media and Displacement Performance of a SILICA/PAM Nanohybrid: Experimental and Numerical Simulation Study

Nanoparticles (NPs) have been proposed as additives to improve the rheological properties of polymer solutions and reduce mechanical degradation. This study presents the results of the retention experiment and the numerical simulation of the displacement efficiency of a SiO2/hydrolyzed polyacrylamide (HPAM) nanohybrid (CSNH-AC). The CSNH-AC was obtained from SiO2 NPs (synthesized by the Stöber method) chemically modified with HPAM chains. Attenuated total reflection-Fourier transform infrared spectroscopy, field emission gun-scanning electron microscopy, X-ray diffraction, and thermogravimetric analysis were used to characterize the nanohybrid. The injectivity and dynamic retention tests were performed at 56 °C in a sandstone core with a porosity of ∼26% and a permeability of 117 and 287 mD. A history matching of the dynamic retention test was performed to determine the maximum and residual adsorption, IPV, and residual resistance factor (RRF). A laboratory-scale model was used to evaluate the displacement efficiency of CSNH-AC and HPAM through numerical simulation. According to the results, the nanohybrid exhibits better rheological behavior than the HPAM solution at a lower concentration. The nanopolymer sol adsorption and IPV (29,7 μg/grock, 14,5) are greater than those of the HPAM solution (9,2 μg/grock, 10), which was attributed to the difference between the rock permeabilities used in the laboratory tests (HPAM: 287 mD and CSNH-AC: 117 mD). The RF of both samples gradually increases with the increase in shear rate, while the RRF slightly decreases and tends to balance. However, the nanopolymer sol exhibits greater RF and RRF values than that of the polymer solution due to the strong flow resistance of the nanohybrid (higher retention in the porous media). According to the field-scale simulation, the incremental oil production could be 295,505 and 174,465 barrels for the nanopolymer sol and the HPAM solution, respectively (compared to waterflooding). This will represent an incremental recovery factor of 11.3% for the nanopolymer sol and 6.7% for the HPAM solution.

A comprehensive review of viscoelastic polymer flooding in sandstone and carbonate rocks

Polymer flooding is a proven chemical Enhanced Oil Recovery (cEOR) method that boosts oil production beyond waterflooding. Thorough theoretical and practical knowledge has been obtained for this technique through numerous experimental, simulation, and field works. According to the conventional belief, this technique improves macroscopic sweep efficiency due to high polymer viscosity by producing moveable oil that remains unswept after secondary recovery. However, recent studies show that in addition to viscosity, polymer viscoelasticity can be effectively utilized to increase oil recovery by mobilizing residual oil and improving microscopic displacement efficiency in addition to macroscopic sweep efficiency. The polymer flooding is frequently implemented in sandstones with limited application in carbonates. This limitation is associated with extreme reservoir conditions, such as high concentrations of monovalent and divalent ions in the formation brine and ultimate reservoir temperatures. Other complications include the high heterogeneity of tight carbonates and their mixed-to-oil wettability. To overcome the challenges related to severe reservoir conditions, novel polymers have been introduced. These new polymers have unique monomers protecting them from chemical and thermal degradations. Monomers, such as NVP (N-vinylpyrrolidone) and ATBS (2-acrylamido-2-methylpropane sulfonic acid), enhance the chemical resistance of polymers against hydrolysis, mitigating the risk of viscosity reduction or precipitation in challenging reservoir conditions. However, the viscoelasticity of these novel polymers and their corresponding impact on microscopic displacement efficiency are not well established and require further investigation in this area. In this study, we comprehensively review recent works on viscoelastic polymer flow under various reservoir conditions, including carbonates and sandstones. In addition, the paper defines various mechanisms underlying incremental oil recovery by viscoelastic polymers and extensively describes the means of controlling and improving their viscoelasticity. Furthermore, the polymer screening studies for harsh reservoir conditions are also included. Finally, the impact of viscoelastic synthetic polymers on oil mobilization, the difficulties faced during this cEOR process, and the list of field applications in carbonates and sandstones can also be found in our work. This paper may serve as a guide for commencing or performing laboratory- and field-scale projects related to viscoelastic polymer flooding.

A single-molecule study on polymer fluid dynamics in porous media

Understanding the dynamic behavior of polymeric fluids in porous media is essential for vast geoscience applications, particularly enhanced oil recovery and polymer-enhanced soil washing, to clean up soil contamination. During the past decades, the behavior of polymeric fluids in microscopic space has only been investigated using ensemble-averaged experimental methods in which a bulk phase behavior of the fluids characterizes flow mechanisms. Multiple flow mechanisms have been proposed based on ensemble-averaged data; however, microscale characterization of the interactions between polymers and solid surfaces and the mechanisms governing polymer retention and permeability reduction as well as the reversibility of polymer retention are lacking, resulting in a limited understanding of the flow mechanisms. Here we report direct visualization and multi-scale characterization of the dynamic behavior of polymer molecules in a representative porous medium by integrating microfluidics with single-molecule imaging. We demonstrate that the polymers' adsorption, entrapment and hydrodynamic retention contribute to their overall retention in porous media. Our study illustrates how microfluidics can help in understanding the dynamic behavior of polymers, their interactions with the solid/fluid interface and their effects on flow properties. Additionally, it demonstrates the role of microfluidic platforms in providing a more representative and accurate model for polymer retention and permeability reduction in porous media. The obtained insights encourage the development of improved models that better capture the behavior of complex fluids in confined environments and have significant implications for a wide range of applications in geoscience, materials science, and rheology.

Experimental and numerical investigation of polymer pore-clogging in micromodels

Polymers have been used effectively in the Oil & Gas Industry for a variety of field applications, such as enhanced oil recovery (EOR), well conformance, mobility control, and others. Polymer intermolecular interactions with the porous rock, in particular, formation clogging and the associated alterations to permeability, is a common problem in the industry. In this work, fluorescent polymers and single-molecule imaging are presented for the first time to assess the dynamic interaction and transport behavior of polymer molecules utilizing a microfluidic device. Pore-scale simulations are performed to replicate the experimental observations. The microfluidic chip, also known as a "Reservoir-on-a-Chip" functions as a 2D surrogate to evaluate the flow processes that take place at the pore-scale. The pore-throat sizes of an oil-bearing reservoir rock, which range from 2 to 10 nm, are taken into consideration while designing the microfluidic chip. Using soft lithography, we created the micromodel from polydimethylsiloxane (PDMS). The conventional use of tracers to monitor polymers has a restriction due to the tendency of polymer and tracer molecules to segregate. For the first time, we develop a novel microscopy method to observe the dynamic behavior of polymer pore-clogging and unclogging processes. We provide direct dynamic observations of polymer molecules during their transport within the aqueous phase and their clustering and accumulations. Pore-scale simulations were carried out to simulate the phenomena using a finite-element simulation tool. The simulations revealed a decline in flow conductivity over time within the flow channels that experienced polymer accumulation and retention, which is consistent with the experimental observation of polymer retention. The performed single-phase flow simulations allowed us to assess the flow behavior of the tagged polymer molecules within the aqueous phase. Additionally, both experimental observation and numerical simulations are used to evaluate the retention mechanisms that emerge during flow and how they affect apparent permeability. This work provides new insights to assessing the mechanisms of polymer retention in porous media.

Comprehensive Investigation of Dynamic Characteristics of Amphoteric Surfactant-Sulfonated Polymer Solution on Carbonate Rocks in Reservoir Conditions

To recover the remaining oil after water flooding, amphoteric surfactant-sulfonated polymer (S-P) flooding has attracted attention as a tertiary oil recovery technique. Oil recovery by S-P flooding not only is influenced by reservoir heterogeneity but also depends on chemical adsorption and interactions of S-P solution with the surface of rocks. This paper presents comprehensive laboratory results related to the dynamic adsorption, resistance factor (RF), residual resistance factor (RRF), and adsorbed layer thickness of S-P solution on the surface of carbonate rocks. Three core flooding experiments were conducted. The S-P solution was composed of an amphoteric surfactant (0.2 wt %) and sulfonated polymer solution (0.2 wt %) in seawater. The S-P solution was injected until the effluent concentration reached the inlet concentration. Seawater was injected after S-P injection to displace S-P solution until the effluent concentration reduced to a minimum value or constant value for desorption study. Total organic carbon (TOC) and Hyamine methods were used to determine the adsorption of the polymer and surfactant, respectively. The individual amount of dynamic adsorption and the total amount of adsorption of S-P solution onto carbonate rock were determined and compared with the results of single adsorption of a surfactant solution published previously. The residual resistance factor, resistance factor, and adsorbed layer thickness of S-P solution on carbonate rocks were calculated based on the differential pressure before and after injecting the S-P solution. We found that the dynamic adsorption, RF, RRF, and adsorbed layer thickness of the S-P solution strongly depends on pore geometry or reservoir properties. Some of the relationships are proposed for the first time. The loss of injectivity and liquid permeability during S-P solution injection are evaluated in detail in this paper. This paper presents insights into the dynamic adsorption, residual resistance factor, resistance factor, adsorbed layer thickness, and injectivity of S-P solution on carbonate rocks with reservoir parameters, which could help in designing the chemical enhanced oil recovery process in carbonate reservoirs.

An Experimental Study on Hydrodynamic Retention of Low and High Molecular Weight Sulfonated Polyacrylamide Polymer

Polymers are often added with water as a viscosifier to improve oil recovery from hydrocarbon reservoirs. Polymer might be lost wholly or partially from the injected polymer solution by adsorption on the grain surfaces, mechanical entrapment in pores, and hydrodynamic retention in stagnant zones. Therefore, having a clear picture of polymer losses (and retention) is very important for designing a technically and economically successful polymer flood project. The polymer adsorption and mechanical entrapment are discussed more in depth in the literature, though the effect of hydrodynamic retention can be just as significant. This research investigates the effect of the hydrodynamic retention for low and high molecular weight (AN 113 VLM and AN 113 VHM) sulfonated polyacrylamide polymer. Two high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods. Polymer retention was first determined by injecting 1 cm³/min, followed by polymer core floods at 3, 5, and 8 cm³/min to determine the hydrodynamic retention (incremental retention). A higher molecular weight polymer (AN 113 VHM) showed higher polymer retention. In contrast, hydrodynamic retention for lower molecular weight (AN 113 VLM) was significantly higher than that of the higher molecular weight polymer. Other important observations were the reversibility of the hydrodynamic retention, no permanent permeability reduction, the shear thinning behavior in a rheometer, and shear thickening behavior in core floods.

An Overview on Polymer Retention in Porous Media

Polymer flooding is an important enhanced oil recovery technology introduced in field projects since the late 1960s. The key to a successful polymer flood project depends upon proper estimation of polymer retention. The aims of this paper are twofold. First, to show the mechanism of polymer flooding and how this mechanism is affected by polymer retention. Based on the literature, the mobility ratio significantly increases as a result of the interactions between the injected polymer molecules and the reservoir rock. Secondly, to provide a better understanding of the polymer retention, we discussed polymer retention types, mechanisms, factors promoting or inhibiting polymer retention, methods and modeling techniques used for estimating polymer retention.

Reservoir-on-a-chip (ROC): a new paradigm in reservoir engineering

In this study, we design a microfluidic chip, which represents the pore structure of a naturally occurring oil-bearing reservoir rock. The pore-network has been etched in a silicon substrate and bonded with a glass covering layer to make a complete microfluidic chip, which is termed as 'Reservoir-on-a-chip' (ROC). Here we report, for the first time, the ability to perform traditional waterflooding experiments in a ROC. Oil is kept as the resident phase in the ROC, and waterflooding is performed to displace the oil phase from the network. The flow visualization provides specific information about the presence of the trapped oil phase and the movement of the oil/water interface/meniscus in the network. The recovery curve is extracted based on the measured volume of oil at the outlet of the ROC. We also provide the first indication that this oil-recovery trend realized at chip-level can be correlated to the flooding experiments related to actual reservoir cores. Hence, we have successfully demonstrated that the conceptualized 'Reservoir-on-a-Chip' has the features of a realistic pore-network and in principle is able to perform the necessary flooding experiments that are routinely done in reservoir engineering.