Nanoparticle-stabilized CO2 Foam Research Articles

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO2 co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO2, Al2O3 nanoparticles, anionic surfactant SDS, and CO2 in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO2 foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO2 from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.

Laboratory study on the rheology properties of nanoparticle-stabilized supercritical CO2 foam

Adding nanoparticles (NPs) into surfactant solution has been widely employed in improving foam stability in CO2 Enhanced Oil Recovery (EOR) applications. To help understand the foam flow characteristics in porous media, the rheology behavior of the NP-stabilized CO2 foam is experimentally investigated in this paper. The foam fluid is treated as a non-Newtonian fluid obeying the power law constitutive equation, and the effect of CO2 phase state, oil presence as well as solution salinity on the power law index, and the apparent viscosity of the NP-stabilized foam is scrutinized. Different rheology behavior between the NP-stabilized gaseous CO2 foam and the supercritical CO2 (ScCO2) foam is revealed in the both power law index and the apparent viscosity results. The NP-stabilized gaseous CO2 foam shows the rheology transition behavior from shear thickening to shear thinning with increasing shear rates and supplies maximal foam apparent viscosity of 27.7 mPa s, whereas the NP-stabilized ScCO2 foam shows the universal shear thickening behavior in the studied shear rate range with much higher maximum apparent viscosity of 95.8 mPa s. It is found the apparent viscosity of the NP-stabilized ScCO2 foam could reach up to 210.9 mPa s under the oil presence conditions, while 5 wt% NaCl existence in the aqueous solution could result in slightly lower apparent viscosity of 80.3 mPa s.

Multi-parameter screening study on the static properties of nanoparticle-stabilized CO2 foam near the CO2 critical point

The important role of nanoparticles (NPs) on foam stabilization under harsh geological conditions has been well recognized. In this paper, the Orthogonal Experimental Design (OED) method is adopted to investigate the synergy effects of six parameters, including NP concentration, surfactant concentration, oil concentration, salinity, temperature, and pressure, under five levels in the range of 0–0.2 wt%, 0.1–0.5 wt%, 0–4 wt%, 0–8 wt%, 20–60 °C, and 5.5–9.5 MPa respectively. K values and B values obtained in the OED experiments are employed to show the single parameter effect and the importance of each influential factor on foam static properties. It is concluded that system temperature and pressure, which has the highest B values of 22 mm and 18 mm on foam height results, are the dominant parameters on foamability, whereas temperature with B values of 80% on foam decay rate is the dominant factor on foam stability. It is observed when the system condition is close to the CO2 critical point, the foamability and stability of the NP-stabilized foam are much worse than under conditions far from the critical point. At last, optimal formulation of surfactant and NP concentration is proposed and validated for two geological cases of 45 °C and 55 °C with salinity and oil presence. It is expected the experimental technique, as well as the research results, reported in this paper could help the laboratory screening and formulation optimization of the complex NP-stabilized ScCO2 foam system.

Nanoparticle-stabilized CO2 foam to improve conventional CO2 EOR process and recovery at Batı Raman oil field, Turkey

(B.Raman), which is the largest oil field of Turkey's already existing CO2 injection system, does not produce at the desired efficiency due to the natural fracture characteristics. Therefore, this research is performed to control the CO2 mobility in the reservoir by creating nanoparticle stabilized CO2 foam using the property of nanoparticles to be adsorbed at the gas-water interface permanently and to achieve additional oil recovery at the B. Raman oil field. In the initial stage of the research, dispersion stabilization and foamability of different nano-silicas are considered. The effects of nanoparticle concentration, salinity, temperature, and pH on foamability and dispersion stabilization were examined. Research results suggested that half hydrophobicity, salt addition, and increased concentration positively affect foamability, whereas the salinity value above 1% generated flocculation. Also, although the foam with half hydrophobic nano-silica named H30 has better foamability, this foam could not be stabilized. The effects of pressure, phase ratio, and flow rate on foam formation were also studied. The better foam was observed at the observation cell when the CO2 to Nano dispersion phase ratio was 1. It was also found that the pressure should be above 1100 psi where the CO2 was in the supercritical phase to create the foam with the current core flooding system. Then, the oil recovery test was conducted with suitable nanoparticles, particularly the PEG and CC301. Before using nano-silica particles, CO2 injection and then WAG was applied to the core sample to express the B. Raman field case. The results indicate that foam application is successful if appropriate conditions exist.

Rheology and stability of nanoparticle-stabilized CO2 foam under reservoir conditions

This study investigates the rheology and stability of nanoparticle-stabilized CO2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Γ), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO2 foam apparent viscosity featured a mountain-shaped curve versus Γ, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.

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

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.

Enhancement of storage capacity of CO2 in megaporous saline aquifers using nanoparticle-stabilized CO2 foam

Carbon dioxide sequestration in saline aquifers is a promising approach to reduce anthropogenic CO2 emissions and mitigate global climate change. CO2 storage capacity in aquifers depends on various factors such as interfacial tension, injection rate, viscosity ratio and characteristics of the porous media. We investigate the effects of these variables on CO2 gas and foam injection into a brine-saturated porous medium using a glass fabricated microfluidic device. The pore network is a representation of Washita-Fredericksburg formation located at a depth of 1110 m that is part of a saline aquifer located in southeast US and is currently under investigation to estimate its storage capacity as a commercial-scale CO2 storage hub. Contact angles and interfacial tensions between different fluids are measured under the experimental conditions. The three different injection rates are studied for each gaseous and foam injection. The displacement patterns images are captured by a high-resolution camera with an achromatic 60 M P sensor, and displacement performances are analyzed. CO2 foam injection appears to significantly increase CO2 storage in the microfluidic device (20%–40% higher compared to gas injection). Thus, CO2 foam injection is a promising approach to reduce CO2 mobility and enhance storage capacity in the target formation.

The effect of foam quality, particle concentration and flow rate on nanoparticle-stabilized CO2 mobility control foams.

CO2 foam is regarded as a promising technology and widely used in the oil and gas industry, not only to improve oil production, but also to mitigate carbon emissions through their capture. This paper describes a series of nanoparticle-stabilized CO2 foam generation and foam flow experiments under reservoir conditions. Stable CO2 foam was generated when CO2 and a nanosilica dispersion flowed through the core sample under 1500 psi and 25 °C. The foam changed from a fine-texture foam to a coarse foam as the foam quality increased from 20% to 95%. Foam mobility increased slightly with the increasing foam quality from 20% to 80% and then rapidly from 80% to 95%. A stable CO2 foam was generated as the nanosilica concentration increased to 2500 ppm. Foam mobility and resistance factor increased with the increasing nanosilica concentration. As the injection flow rate increased to 60 ml h−1, stable and fine-texture CO2 foam was obtained. Foam mobility was observed to remain almost constant as the injection flow rate increased from 60 ml h−1 to 150 ml h−1.

Modeling of Nanoparticle-Stabilized CO2 Foam Enhanced Oil Recovery

Summary Previous experimental studies show that “nanoparticle-stabilized” supercritical carbon dioxide (CO2) foams (NP-stabilized CO2 foams or NP CO2 foams in this paper) can be applied as an alternative to surfactant foams, to reduce CO2 mobility in gas-injection enhanced oil recovery (EOR). The NPs, if chosen correctly, can be effective foam stabilizers attached at the fluid interface in a wide range of physicochemical conditions. By using NP CO2 foam experiments available in the literature, this study investigates the applicability of NP foams for mobility control and, thus, improved sweep efficiency. This study consists of two tasks: (1) presenting how a population-balance mechanistic foam model can be used to fit experimental data and determine required model parameters and (2) examining sweep efficiency in a condition resembling Lisama Field (a five-spot pattern with four producers and one injector in the middle), by using relevant gas mobility-reduction factors (MRFs) derived from the mechanistic-modeling technique. The field-scale simulations are conducted with Computer Modeling Group (CMG) software, contrasting NP and surfactant foams (in both dry and wet foam-injection conditions) to a gas-only injection and a gas/water coinjection (no foam). The results show how the model can successfully reproduce coreflood experimental data, creating three different foam states (weak foam, strong foam, and intermediate) and two steady-state strong-foam regimes (high quality and low quality). When the gas-phase MRFs, ranging up to 10 from the model fit, are applied in the field-scale simulations, the use of NPs improves oil recovery compared with a gas/water coinjection, but not as efficiently as a successful surfactant foam injection does. This implies that, although NP-stabilized foams do provide some benefits, there still seems to be some room to improve the stability and the strength of resulting foams.

Nanoparticle-stabilized CO2 foam for waterflooded residual oil recovery

This paper presents a series of studies of nanoparticle-stabilized CO2-foam for waterflooded residual oil recovery. A stable CO2 foam was generated as CO2/nanosilica dispersion flowed through a porous media. The generated CO2 foam could reduce CO2 mobility and improve CO2 sweep efficiency in CO2 flooding. The particle-stabilized CO2 foam has also been observed to improve residual oil recovery after waterflooding. Effects of pressure and temperature on the performance of the CO2 foam in residual oil recovery were investigated. The results indicated that the residual oil recovery (percentage of waterflooded residual oil) by CO2/nanosilica flooding increased from 64.9% to 75.8% when the pressure was increased from 1200 psi to 2500 psi. When temperature increased from 25 °C to 60 °C, the residual oil recovery by CO2/nanosilica flooding decreased from 62.6% to 52.1%.

An experimental investigation of nanoparticle-stabilized CO2 foam used in enhanced oil recovery

Stability of nanoparticle (NP) stabilized CO2 foam using silica and nanoclay, and the resulting improvement in oil recovery are investigated using modified bulk foam tests and flow experiments using a microfluidic device. The size and uniformity of the dispersion of NPs are characterized via Dynamic Light Scattering. The NP-assisted foam properties are evaluated by: (1) modified bulk foam tests where bulk foam is generated using CO2 under approximately 20psi of pressure and its formability and decay (dynamic stability) are recorded as functions of time and (2) foam stability and oil recovery are investigated using a quasi-2D porous medium (microfluidic chip), fabricated based on a 2D representation of a sample of sandstone. The effects of type of NP, particle size, surfactant type and pressure on CO2 foam stability and viscosity and the resulting incremental oil recovery are investigated and discussed. The results show that nanoclay and silica NPs with an Alpha-Olefin Sulfonate (AOS)-Lauramidopropyl Betaine (LAPB) surfactant mixture provide excellent formability and stability (half-life time around four hours) and increased viscosity. The stability and impact of NPs-stabilized foam on recovery in a microfluidic device is explored and reported. Data is collected using an ultra-high resolution full frame image sensor, which allows the entire surface of the model to be unobstructed for observation; images of the entire porous medium are captured while preserving the resolution required to discern features as small as 10μm. The porous medium is approximately 1.4in. in width and 1.6in. in length and the channels are 20μm deep. Results suggest that foam with highest stability (Si-LAPB-AOS) does not provide the best oil recovery performance (a high oil recovery and a low pore volume injected). The novelty of this work lies in its thorough characterization of NPs in stabilizing CO2 foams, investigation of their stability using a modified bulk foam test and examination of their stability and incremental recovery resulting from their use compared to systems without NPs in quasi-2D porous media fabricated based on a two-dimensional representation of a Berea sandstone.

Mobility Investigation of Nanoparticle-Stabilized Carbon Dioxide Foam for Enhanced Oil Recovery (EOR)

Enhanced oil recovery (EOR) can extend the life of an oil field by providing additional drive mechanism to the crude oil. The use of carbon dioxide (CO2) in EOR application has shown a good potential, but it has some weaknesses such as viscous fingering. Viscous fingering problem can be solved by reducing the CO2 gas mobility, which can be achieved by transforming the CO2 gas into surfactant-stabilized foam. However, surfactant-stabilized foam is not very stable under harsh reservoir condition, which could be handled by introducing nanoparticle-stabilized CO2 foam. Thus, this paper aims to investigate the mobility of nanoparticle-stabilized CO2 foam at varying brine salinity (1 - 4 wt%), concentration of AOS surfactant (0.01 - 1 wt%) and concentration of nanoparticle (0.05 - 1 wt%). The volumetric phase ratio was fixed at 8 CO2/aqueous. The sand pack foam flooding test was conducted to measure the effectiveness of the formulated foam to displace the oil inside the porous medium through mobility and oil recovery measurement. It was found that foam mobility is inversely proportional to oil recovery. Mobility decreased when increase of brine salinity, surfactant and nanoparticle concentration, which has increased the oil recovery. Thus, it is important to reduce the foam mobility for efficient displacement process, which could minimize viscous fingering and enhance the oil recovery. This could be achieved by increasing the viscosity of displacing fluid (foam) for more stable displacement in EOR application.

Pore-Scale Assessment of Nanoparticle-Stabilized CO2 Foam for Enhanced Oil Recovery

In this paper, we evaluate nanoparticle-stabilized CO2 foam stability and effectiveness in enhanced oil recovery at the pore and micromodel scales. The nanoparticle-stabilized CO2 gas-in-brine foams maintain excellent stability within microconfined media and continue to be stable after 10 days, as compared to less than 1 day for surfactant foam. The nanoparticle-stabilized CO2 foams are shown to generate a 3-fold increase in oil recovery (an additional 15% initial oil in place), as compared to an otherwise similar CO2 gas flood. Fluorescence imaging is applied to quantify emulsion size distribution (down to 1 μm) in both CO2 and nanoparticle-stabilized CO2 foam flood cases. Nanoparticle-stabilized CO2 foam flooding results in significantly smaller oil-in-water emulsion sizes with an average size of 1.7 μm (∼80% smaller than a CO2 gas flood), with negligible impact on water-in-oil emulsions. The effectiveness of nanoparticle-stabilized CO2 foam is compared for representative light, medium, and heavy oils. ...