scholarly journals The Investigation of Silica Nanoparticles-CO2 Foam Stability for Enhancing Oil Recovery Purpose

2020 ◽  
Vol 9 (1) ◽  
pp. 36-45
Author(s):  
David Maurich
Keyword(s):  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Volume Ratio ◽  
Mobility Ratio ◽  
Phase Volume ◽  
Sweep Efficiency ◽  
Co2 Gas ◽  
Phase Volume Ratio ◽  
Co2 Foam ◽  
Brine Salinity

Carbon dioxide (CO2) gas injection is one of the most successful Enhanced Oil Recovery (EOR) methods. But the main problem that occurs in immiscible CO2 injection is the poor volumetric sweep efficiency which causes large quantities of the oil to be retained in pore spaces of reservoir. Although this problem can be improved through the injection of surfactant with CO2 gas where the surfactant will stabilize CO2 foam, this method still has some weaknesses due to foam size issue, surfactants compatibility problems with rocks and reservoir fluids and are less effective at high brine salinity and reservoir temperature such as typical oil reservoirs in Indonesia. This research aims to examine the stability of the foams/emulsions, compatibility and phase behavior of suspensions generated by hydrophobic silica nanoparticles on various salinity of formation water as well as to determine its effect on the mobility ratio parameter, which correlate indirectly with macroscopic sweep efficiency and oil recovery factor. This research utilizes density, static foam, and viscosity test which was carried out on various concentrations of silica nanoparticles, brine salinity and phase volume ratio to obtain a stable foam/emulsion design. The results showed that silica nanoparticles can increase the viscosity of displacing fluid by generating emulsions or foams so that it can reduce the mobility ratio toward favorable mobility, while the level of stability of the emulsion or foam of the silica nanoparticles suspension is strongly influenced by concentration, salinity and phase volume ratio. The high resistance factor of the emulsions/foams generated by silica nanoparticles will promote better potential of these particles in producing more oil.

Performance of Silica Nanoparticles in CO2 Foam for EOR and CCUS at Tough Reservoir Conditions

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 406-415 ◽  
Author(s):  
Arthur U. Rognmo ◽  
Noor Al-Khayyat ◽  
Sandra Heldal ◽  
Ida Vikingstad ◽  
Øyvind Eide ◽  
...  
Keyword(s):  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Elevated Temperatures ◽  
Co2 Storage ◽  
Sweep Efficiency ◽  
Co2 Foam ◽  
Reservoir Conditions ◽  
Incremental Oil Recovery ◽  
Surface Modified

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

Enhanced Experimental Carbon Dioxide Sweep Using Surface Coated Silica Nanoparticles as a Foaming Agent

2021 ◽  
Author(s):  
Ahmad Alfakher ◽  
David A. DiCarlo
Keyword(s):  
Carbon Dioxide ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Graphical Representation ◽  
Co2 Flooding ◽  
Sweep Efficiency ◽  
Foaming Agent ◽  
The Core ◽  
Co2 Foam

Abstract Solvent flooding is a well-established method of enhanced oil recovery (EOR), with carbon dioxide (CO2) being the most-often used solvent. As CO2 is both less viscous and less dense than the fluids it displaces, the displacement suffers from poor sweep efficiency caused by an unfavorable mobility ratio and unfavorable gravity number. Creating in-situ CO2 foam improves the sweep efficiency of CO2 floods. Another application is the injection of CO2 foam into saline aquifers for carbon capture and storage (CCS). The goal of the core flood experiments in this paper was to study the effectiveness of surface coated silica nanoparticles as an in-situ CO2 foaming agent. In each experiment, the pressure drop was measured across five separate sections in the core, as well as along the whole core. In addition, the saturation distribution in the core was calculated periodically using computed tomography (CT) scanning measurements. The experiments consisted of vertical core floods where liquid CO2 displaced brine from the top to the bottom of the core. A flood with surface coated silica nanoparticles suspended in the brine is performed in the same core and at the same conditions to a flood with no nanoparticles, and results from these floods are compared. In these experiments, breakthrough occurred 45% later with foamed CO2, and the final CO2 saturation was also 45% greater than with the unfoamed CO2. The study shows how nanoparticles stabilize the CO2 front. The results provide quantitative information on, as well as a graphical representation of, the behavior of the CO2 foam front as it advances through the core. This data can be used to upscale the behavior observed and properties calculated from the core-scale to the reservoir-scale to improve field applications of CO2 flooding.

Unit Mobility Ratio Displacement Calculations for Pattern Floods in Homogeneous Medium

1966 ◽  
Vol 6 (03) ◽  
pp. 217-227 ◽  
Author(s):  
Hubert J. Morel-Seytoux
Keyword(s):  
Oil Recovery ◽  
Numerical Solutions ◽  
Mobility Ratio ◽  
Finite Difference Approximation ◽  
Difference Approximation ◽  
Numerical Techniques ◽  
Sweep Efficiency ◽  
Closed Form Solutions ◽  
Regular Patterns ◽  
Quantities Of Interest

Abstract The influence of pattern geometry on assisted oil recovery for a particular displacement mechanism is the object of investigation in this paper. The displacement is assumed to be of unit mobility ratio and piston-like. Fluids are assumed incompressible and gravity and capillary effects are neglected. With these assumptions it is possible to calculate by analytical methods the quantities of interest to the reservoir engineer for a great variety of patterns. Specifically, this paper presentsvery briefly, the methods and mathematical derivations required to obtain the results of engineering concern, andtypical results in the form of graphs or formulae that can be used readily without prior study of the methods. Results of this work provide checks for solutions obtained from programmed numerical techniques. They also reveal the effect of pattern geometry and, even though the assumptions of piston-like displacement and of unit mobility ratio are restrictive, they can nevertheless be used for rather crude but quick, cheap estimates. These estimates can be refined to account for non-unit mobility ratio and two-phase flow by correlating analytical results in the case M=1 and the numerical results for non-Piston, non-unit mobility ratio displacements. In an earlier paper1 it was also shown that from the knowledge of closed form solutions for unit mobility ratio, quantities called "scale factors" could be readily calculated, increasing considerably the flexibility of the numerical techniques. Many new closed form solutions are given in this paper. INTRODUCTION BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected. BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected.

scholarly journals Enhanced Oil Recovery: Chemical Flooding

2021 ◽  
Author(s):  
Ahmed Ragab ◽  
Eman M. Mansour
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Phase ◽  
Mobility Ratio ◽  
Chemical Flooding ◽  
Sweep Efficiency ◽  
Oil Displacement ◽  
Remaining Oil ◽  
Oil Displacement Efficiency

The enhanced oil recovery phase of oil reservoirs production usually comes after the water/gas injection (secondary recovery) phase. The main objective of EOR application is to mobilize the remaining oil through enhancing the oil displacement and volumetric sweep efficiency. The oil displacement efficiency enhances by reducing the oil viscosity and/or by reducing the interfacial tension, while the volumetric sweep efficiency improves by developing a favorable mobility ratio between the displacing fluid and the remaining oil. It is important to identify remaining oil and the production mechanisms that are necessary to improve oil recovery prior to implementing an EOR phase. Chemical enhanced oil recovery is one of the major EOR methods that reduces the residual oil saturation by lowering water-oil interfacial tension (surfactant/alkaline) and increases the volumetric sweep efficiency by reducing the water-oil mobility ratio (polymer). In this chapter, the basic mechanisms of different chemical methods have been discussed including the interactions of different chemicals with the reservoir rocks and fluids. In addition, an up-to-date status of chemical flooding at the laboratory scale, pilot projects and field applications have been reported.

Pore-to-Core EOR Upscaling for CO2 Foam for CCUS

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2793-2803 ◽  
Author(s):  
Arthur Uno Rognmo ◽  
Sunniva Brudvik Fredriksen ◽  
Zachary Paul Alcorn ◽  
Mohan Sharma ◽  
Tore Føyen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Apparent Viscosity ◽  
Shear Thinning ◽  
Liquid Films ◽  
Carbonate Reservoir ◽  
Sweep Efficiency ◽  
Reference Case ◽  
Foam Generation ◽  
Co2 Foam ◽  
Gas Fractions

Summary This paper presents an ongoing CO2–foam upscaling research project that aims to advance CO2–foam technology for accelerating and increasing oil recovery, while reducing operational costs and lessening the carbon footprint left during CO2 enhanced oil recovery (EOR). Laboratory CO2–foam behavior was upscaled to pilot scale in an onshore carbonate reservoir in Texas, USA. Important CO2–foam properties, such as local foam generation, bubble texture, apparent viscosity, and shear–thinning behavior with a nonionic surfactant, were evaluated using pore–to–core upscaling to develop accurate numerical tools for a field–pilot prediction of increased sweep efficiency and CO2 utilization. At pore–scale, high–pressure silicon–wafer micromodels showed in–situ foam generation and stable liquid films over time during no–flow conditions. Intrapore foam bubbles corroborated high apparent foam viscosities measured at core scale. CO2–foam apparent viscosity was measured at different rates (foam–rate scans) and different gas fractions (foam–quality scans) at core scale. The highest mobility reduction (foam apparent viscosity) was observed between 0.60 and 0.70 gas fractions. The maximum foam apparent viscosity was 44.3 (±0.5) mPa·s, 600 times higher than that of pure CO2, compared with the baseline viscosity (reference case, without surfactant), which was 1.7 (±0.6) mPa·s, measured at identical conditions. The CO2–foam showed shear–thinning behavior with approximately 50% reduction in apparent viscosity when the superficial velocity was increased from 1 to 8 ft/D. Strong foam was generated in EOR corefloods at a gas fraction of 0.70, resulting in an apparent viscosity of 39.1 mPa·s. Foam parameters derived from core–scale foam floods were used for numerical upscaling and field–pilot performance assessment.

scholarly journals Partitioning of cerrena unicolor laccase activity in an aqueous two-phase system

2016 ◽  
Vol 37 (2) ◽  
pp. 269-280 ◽  
Author(s):  
Michał Blatkiewicz ◽  
Axel Prinz ◽  
Andrzej Górak ◽  
Stanisław Ledakowicz
Keyword(s):  
Volume Ratio ◽  
Line Length ◽  
Bottom Phase ◽  
Phase System ◽  
Phase Volume ◽  
Two Phase ◽  
Aqueous Two Phase System ◽  
Phase Volume Ratio ◽  
Cerrena Unicolor ◽  
Tie Line

Abstract Culture supernatant containing laccase produced by Cerrena unicolor strain was used to examine laccase partitioning between phases in an aqueous two-phase system. The investigated system consisted of polyethylene glycol 3000 and sodium phosphate buffer adjusted to pH = 7. Influence of several parameters on partitioning was measured, including phase forming components’ concentrations, tie line lengths, phase volume ratio, supernatant dilution, process temperature and halogen salt supplementation. Partitioning coefficients up to 78 in the bottom phase were achieved with yields of over 90%. Tie line length and phase volume ratio had significant effect on enzyme partitioning.

The Effect of Phase Volume Ratio on Emulsion Type*

1954 ◽  
Vol 43 (2) ◽  
pp. 117-119 ◽  
Author(s):  
Rupert Salisbury ◽  
E.E. Leuallen ◽  
L.T. Chavkin
Keyword(s):  
Volume Ratio ◽  
Phase Volume ◽  
Phase Volume Ratio
Sign in / Sign up

Export Citation Format

Share Document