Oil recovery using Smart Water technology (SWF) can be maximized by optimizing the composition of injected water. Brine optimization is also believed to improve Polymer Flooding (PF) performance. The present study aims to assess and define the potential impact of combining Smart Water with Polymer Flooding, based on the sulphates presence in formation/injection water and rock composition. In this work, we study the impact of sulphates (sodium sulphates) on polymer viscoelasticity and its performance in porous media, based on oil recovery and pressure response. Brine composition is optimized after having synthetic sea water (SSW) as a base brine. Brine optimization is performed by doubling the amount of sulphates, whilst diluting (in fresh water) the SSW-brine to a tenth of its initial concentration. Thus, four brines were utilized: 1) SSW (formation water), 2) SSW but double sulphates, 3) SSW/10 and 4) Brine 2/10. The workflow included core plugs aging prior core flooding. Secondary tertiary and quaternary mode experiments were performed to evaluate the feasibility of applying both processes. The SSW-brine optimization (a tenth of its initial concentration) resulted in a salinity of 4.2 g/L which is in good agreement with previous studies (≤5 g/L), to guarantee additional oil recovery using SWF. Polymer rheological characterization was performed over wide range of shear rates and temperatures. Sodium sulphates showed increase in polymer viscosity as compare to sodium chloride or divalent cations. Enhancement in polymer linear viscoelasticity is observed with an increase in sulphate ions concentration. Furthermore, viscosity analysis over temperature has advocated to perform the core flood experiments at 45°C. Fluids were optimized/selected using a comprehensive rheological evaluation (ηoilηpolymer=2). Optimized Smart Water with higher amount of sulphates ions has shown additional oil recovery in both secondary and tertiary mode. Moreover, polymer injection in tertiary mode after smart water injection has shown significant additional oil recovery. This study focuses on the influence of sulphates ions on SWF and PF performance for application in sandstone reservoirs. Previous studies have mainly focused the evaluation of sulphates ions impact only in carbonate reservoirs. It is of importance to further understand/clarify the effect of sulphates for field applications of SWF and PF combined. This in turn, could lead to improve the economics of project performance, by means of incremental oil and the less polymer required.
Design of Smart-Water can be economically attractive owing the presence of excessive water resources (seawater). This paper aims to design Smart-Water in order to analyze its impact on remaining oil saturation reduction and hence improved oil recovery. Moreover, this study evaluates and define the synergies and benefits between high salt smart water and polymer flooding. The paper combines an extensive rheological characterization and core-flooding experiments; performing fluid optimization (change in brine composition and polymer concentration). Synthetic seawater (SSW) is used as the base brine. Optimization is perform by adding/removing specific chemical components in the SSW. Overall, five brines are utilized: 1) SSW, 2) 2*SSW, 3) SSW with double sulphates 3) SSW with quadruple sulphates and 5) SSW without NaCl. Brine 1 and 2 are used as the formation brines, whereas brine 3 to 5 are used as the injection brines to analyze impact of SO4-2 and Na+1 on remaining oil saturation reduction. Secondary and tertiary-mode experiments are performed to evaluate the feasibility of applying Smart-Water injection and its synergies with polymer flood. Smart water with spiked sulphates changed the interfacial tension compare to synthetic seawater. Henceforth smart water injection has contributed to extra oil recovery, resulting on a reduction of the remaining oil saturation due to the improved interfacial rheology and slightly higher IFT. Optimized Smart Water with spiked amount of sulphate has produced the highest oil recovery in secondary mode compared to other brines (in case of both formation brines). Furthermore, higher concentration of the divalent cations in formation brine and spiked amount of Na+1 in injected brine has resulted the significant decrease in remaining oil saturation (2*SSW as formation brine). Combination of smart water and polymer flood has shown significant reduction in remaining oil saturation. Polymer injection after smart water with spiked sulphates has contributed to significant extra oil recovery compare to the other brines owing to the combined effect of improved interfacial rheology and enhanced polymer viscoelasticity.
Utilization of nanoparticles in EOR have gained high attention recently, with good but controversial results reported on improving oil recovery. Within this work two types of nanoparticles are selected and assessed, to determine its effect in oil mobilization. The experimental evaluation is performed using micromodels (EOR chips), in combination with a detailed nanofluids characterization. The workflow presented is a useful approach that can extended among different laboratories as preliminary evaluation. The workflow comprises a set of interrelated steps: 1) Selection and preparation of the Aluminium Oxide (Al2O3) and Titanium Dioxide (TiO2) nanofluids, influenced by recent literature comparisons, 2) Detailed rheological evaluation of nanofluids and oil, 3) Investigation of the Fluid-Fluid interaction by means of the interfacial tension (IFT) and nanoparticles effects in oil viscosity, 4) Two-phase flow experiments using EOR chips (breakthrough and mobilized oil vs PV injected), 5) Image processing analysis, leading to 6) Quantitative and qualitative analysis of the experimental data. As expected, we observed that diluting nanoparticles in fresh water increased the stability compared to brine. It was required the use of a stabilizer to optimize nanofluids characteristics. Unlike reported in the literature where Polyvinylpyrrolidone (PVP) is used, we found that adding Poly(ethylene oxide)-(PEO) leads to a more stable nanofluids. There, seemed to be a tendency for the Al2O3 nanoparticles to reduce the viscosity of the aqueous-phase, when combined with PEO. Moreover, when Al2O3 was added to the oleic-phase increased its viscosity, with a strong dependency of soaking process. The image process analysis allowed to generate algorithms to calculate concentrations and saturations among the two-phase flow experiments. These algorithms proved to be highly beneficial enabling qualitative and also quantitative analysis of mobilized oil zones, as well as plugged areas. The experimental results did not show a significantly strong increase in mobilized oil due to Titanium Dioxide nanofluids, but slightly better results were observed with the Alumnium Oxide nanofluid in a low concentration. Much research in recent years has focused on the study of Silica nanoparticles. Since different other nanoparticles can be commercially found, this work presents additive information to the existing body of literature. Moreover, the workflow presented can be used by fellow researchers as preliminary tool for laboratory evaluations. These, to obtain potential useful insights from oil mobilization by the application of nanoparticles flooding.
We evaluate the polymer, surfactant and alkaline flooding performance in porous media by using an in-house innovative experimental setup. This, to reach an optimum experimental evaluation in an attempt to avoid repeated experimental failures reported in the literature. The workflow presented help us to understand the recorded data with high reliability and accuracy. Moreover, allow working at high temperatures and high salinities in order to mimic reservoir conditions. The evaluation undertaken in this paper comprises four main steps: 1) Fluids preparation and optimization, beginning with an extensive rheological evaluation to define the optimum concentration/composition of the fluids. 2) Calibration of pressure sensors and pumps, and detailed determination of the system's dead volume. 3) Routine core analysis was performed, which included measuring porosity, permeability and pore volume. 4) Spontaneous imbibition experiments, secondary and tertiary mode cEOR flooding experiments. The core flooding experiments were performed at a constant flow rate of 0.15ml/min (equivalent to the field conditions of 1ft/day), then followed by a bump rate after Sor is reached. The constructed setup proved to be beneficial on reducing the experimental failures by showing data reproducibility and precision. Small diameter tubings of 1/16″ minimized the dead volumes and core face differential pressure measurement allowed high accuracy at any injection rate. At elevated temperatures (50°C) polymer flooding in secondary mode showed 2% higher recovery compared to tertiary mode. Similar difference was observed at the ambient temperature. For the conditions evaluated in this work, HPAM polymer showed higher recoveries than those of Bio-polymer at higher temperatures. However, lower recoveries from HPAM were observed at lower temperatures. In terms of surfactant flooding experiments the observed performance is significantly better in secondary compared to tertiary mode, as well as facing significant production of emulsion from suboptimal surfactant solutions. Thoroughly examining these differences in recoveries, two key factors were considered to be of critical interest: initial oil saturation and mobility ratio. Moreover, CT scan imaging allowed assessing capillary end effects during oil saturation. A detailed comparison between dry and saturated core images was performed to insure no capillary end effects existed. Finally, a developed mathematical simulation model permitted to quality check the work and create a benchmark for further evaluations. The workflow presented in this paper helps to close the gaps often discussed in the literature with regards to flooding experimental failures at core plug scale. Thus, it can help fellow researchers to optimize their workflow and enhance the final results to aid in fluid evaluation and assessing the optimum cEOR process.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.