Fly Ash Nanoparticle-Stabilized CO2-in-Water Foams for Gas Mobility Control Applications

Nanoparticles have demonstrated their capacity to increase emulsion stability by forming what is known as a Pickering emulsion, which is predicted to improve EOR processes by improving conformity control. The goal of this work is to develop a novel way of beneficially utilizing the main waste product from coal power-generation plants - fly ash - by generating fly ash nanoparticle-stabilized emulsions for improved mobility control, especially under high-salinity conditions. First, the ball-milling method was used to decrease the grain size of fly ash, which was too big for injection into reservoirs. Second, fly ash nanoparticles were used to measure the synergy between nanoparticles and surfactants in the creation of oil-in-brine emulsions. Third, the emulsion stability was tested using a microscope and a rheometer with three different surfactants (cationic, nonionic, and anionic). Finally, oil replacement experiments were conducted using intra-formation heterogeneous cores to investigate the recovery enhancement effect of in situ injection of fly ash nanoparticles and cationic surfactant (CS). Thermally treated fly ash (TTFA) nanoparticles with an average size of 150 nm were produced using nano-milling and thermal treatment techniques. The use of either a cationic or nonionic surfactant in conjunction with nanoparticles resulted in strong and stable emulsions. The cationic surfactant had the greatest synergy, while the anionic surfactant had the least, indicating that electrostatic interactions with the surfactant and the liquid/liquid interface were key factors. The in-situ emulsion formed by the fly ash nanoparticles and the cationic surfactant (FA-CS) produced an additional 8.5 % of the original oil in place (OOIP) recovery after waterflooding. This indicates that the emulsion has better mobility control performance and higher crude oil recovery. This study not only has the potential to minimize the amount of surfactant used for emulsion-based EOR mobility control of fly ash nanoparticles but also to sequester fly ash in the subsurface strata.

The adsorption of commercial polyoxyethylene nonyl phenols and alkyl benzene sulfonates was studied by measuring the surfactant breakthrough from Berea cores. A rate model that reduces to a Langmuir-type isotherm at equilibrium represented these dynamic results and predicted successfully the equilibrium isotherms determined by static experiments.The ratios of both adsorption and desorption were determined and were observed to increase with the number of ethylene oxide groups. Adsorption of the nonionic surfactant appeared to be by hydrogen bonding and the amount adsorbed per unit of area was the same on a number of metal oxide substrates.Negligible adsorption was observed for sulfonates with an alkyl chain length of 9 or less. Introduction Surfactant adsorption is one of the important features governing the economic viability of chemical flooding processes. However, the adsorption on mineral oxide surfaces is only one of several possible mechanisms leading to surfactant losses.Other mechanisms include precipitation of surfactant in the presence of divalent ions, diffusion of surfactant into dead-end pores, and surfactant partitioning into the oil phase. It is necessary partitioning into the oil phase. It is necessary to minimize the losses by all mechanisms. The work reported here addresses the problem of surfactant adsorption; other mechanisms are not considered.There are a number of approaches that have the potential for minimizing adsorption. The most potential for minimizing adsorption. The most desirable surfactant is one that does not adsorb at all; however, such surfactants may not be effective oil-recovery agents. Sacrificial agents that adsorb in place of the surfactant can be used in a preflush or as a competitive additive to the surfactant slug, but effective agents have not yet been identified.Two aspects of the adsorption process are of interest the rate and the amount adsorbed. Both are examined here. The measurements include the dynamic adsorption of both anionic and nonionic surfactants in Berea cores that are initially filled with brine. The breakthrough curves are represented successfully using a model that accounts for the surface coverage. The rate expression reduces to a Langmuir-type isotherm. The shape of this curve has been verified by conducting static experiments.The study included both nonionic and anionic surfactants. These were not pure surfactants but, in general, they are well characterized. The anionic surfactants were studied because their behavior should-be representative of more complex mixtures such as the petroleum sulfonates that have been regarded as prime candidates for oil-recovery agents. These sulfonates are sensitive to divalent ions and many chemical slugs include quantities of nonionic surfactants to alleviate this difficulty to some extent. Therefore, this study included a systematic study of a particular class of nonionic surfactants. This study is the first to report rates of adsorption and desorption. From this information, the nature of the adsorption can be better understood. THEORY Michaels and Morelos have established that the adsorption of polyanions on kaolin occurs by hydrogen bonding. The specific sites at which this adsorption takes place were not defined. For the adsorption of surfactants, this mechanism can be represented as follows: ....................... (1) SPEJ p. 337

The goal of this work is to evaluate stabilization of foams by a combination of nanoparticles and surfactants. Hydrophilic silica nanoparticles (NP) and anionic surfactants were used in this study. Static foams were generated using surfactants and surfactant-NP mixtures with and without the presence of a crude oil. The decay of the foam height with time was studied and half-lives were determined. The foam drainage behavior and thickness of the foam lamella were studied by fluorescence microscopy. Aqueous foams were created in-situ by co-injecting the surfactant or surfactant-NP mixtures with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). Oil displacement experiments were conducted in Berea cores using surfactant and surfactant-nanoparticle mixture as foaming agents. Static foam tests indicate stabilization effect of nanoparticles on surfactant-nanoparticle foam stability in the absence of crude oil. Lighter crude oils were more destabilizing to foams than heavier oils. Adding nanoparticles even in low concentrations (0.3 wt %) can significantly improve the foam stability and mobility reduction factor in the absence of oil. As the concentration of nanoparticles increased, mobility reduction factor (MRF) of surfactant-nanoparticle foam in a Berea core increased significantly. Fluorescence microscopy elucidated that nanoparticles are trapped in the plateau border as well as lamellas which retard liquid drainage and bubble coalescence. The core floods with a crude oil revealed that the incremental oil recovery by surfactant-NP blend over water flood was about 10% OOIP with an immiscible foam.

Many oil reservoirs are at high temperatures and contain brines of high salinity and hardness. The focus of this work is to develop robust foams stabilized by a mixture of nanoparticles and surfactants for such reservoirs. Two types of silica nanoparticles (Si-NP1, Si-NP2) with different grafted low molecular weight ligands/polymers were used. First, aqueous stability analysis of these nanoparticle dispersions were conducted at high-temperature (80 °C) and high-salinity conditions (API Brine; 8 wt% NaCl and 2 wt% CaCl2). The screened nanoparticles were used in combination with an anionic surfactant. Second, bulk foam and emulsion stability tests were performed to investigate their performance in stabilizing the air–water and oil–water interface, respectively. Third, foam flow experiments in the absence of oil were performed to characterize the foam rheology. Finally, oil displacement experiments were conducted in an in-house, custom-built 2D sand pack with flow visualization. The sand pack had two layers of different mesh size silica sand which yielded a permeability contrast of 6:1. Brine floods followed by foam floods (80% quality) were conducted, and foam flow dynamics were monitored. The grafting of low molecular weight polymers/ligands on silica nanoparticle surfaces resulted in steric stabilization under high-temperature and high-salinity conditions. Foam flow experiments revealed a synergy between Si-NP2 and surfactant in stabilizing foam in the absence of crude oil. In the oil displacement experiments in the layered sand packs, the waterflood recoveries were low (~ 33% original oil in place) due to channeling in the top high-permeability zone, leaving the bottom low-permeability zone completely unswept. Foam flooding with just the surfactant leads to a drastic improvement in sweep efficiency. It resulted in an incremental oil recovery as high as 43.3% OOIP. Different cross-flow behaviors were observed during foam flooding. Significant cross-flow of oil from low-permeability zone to high-permeability zone was observed for the case of surfactant. Conversely, the Si-NP2-surfactant blend resulted in no cross-flow from the low-permeability region with complete blocking of the high-permeability region due to the formation of in situ emulsion. Such selective plugging of high-perm zones using nanoparticles with tailored surface coating and concentration has significant potential in recovering oil from heterogeneous reservoirs.

In enhanced oil recovery (EOR), nanoparticles have gained the potential to improve foam stability. In this study, the potential of fly ash to produce stable foam by using shaker was studied. Fly ash nanoparticles were developed by the mechanical treatment using ball mill. Sample to ball ratio of 1 to 10 was applied to investigate the effect of ball milling on particle size distribution of fly ash. The mechanically activated fly ash was mixed at various concentrations (ppm) with the anionic foaming surfactants AOS14-16. Foam stability tests were performed at ambient conditions by making solution through shaker. Stable foams were generated using varies types of fly ash particles. It was observed that the small sized fly ash has more potential towards foam forming ability and foam stability. Therefore, the mechanically activated fly ash resulted in a considerably increased EOR.

This paper reports the investigation of oil-water IFT behavior when the chromatographic separation of the surfactant mixture occurs during surfactant/alkaline corefloods. In this work, surfactant and alkaline concentrations in the effluent of corefloods and oil-water interfacial tension were determined underdifferent injection strategies. It was found that, in an extended waterflood following an alkaline-surfactant slug injection, surfactant desorbed into the water phase. This desorption of surfactant lasted for a long period of the waterflood. Although the concentration of the desorbed surfactant in the extended waterflood was very low, an ultra-low oil-water IFT was obtained by using a suitable alkaline concentration. Coreflood results showed that an additional 13% of the initial oil in place was recovered after the alkaline/surfactant injection by the synergism of the desorbed surfactant and alkaline. This result indicates that the efficiency and economics of a chemical flood could be improved by utilizing the desorbed surfactant during extended waterflood processes. Introduction In chemical flooding, surfactants are inevitably adsorbed on the surface of reservoir rock by the rock/oil/brine interaction. Surfactant adsorption is one of the important factors governing the economic feasibility of chemical flooding processes.1 Trogus et al.2 examined two aspects of the adsorption process: the rate and the amount of adsorption. They measured the dynamic adsorption of both anionic and nonionic surfactants on Berea cores that were initially saturated with brine. The relative adsorption levels for nonionic and anionic surfactants can be modeled by using a second-orderreversible rate expression that reduces a Langmuir-type adsorption isotherm at equilibrium. It has been shown that the nature of the adsorption isotherm depends to a large extent on the type of surfactant used, the morphological and mineralogical characteristics of the rock, and the type of electrolytes present in solution.3 The adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces.4, 5 Positively charged cationic surfactant will be attracted to negatively charged surfaces, while negatively charged anionic surfactants will be attracted to positively charged surfaces. The salinity and pH of brine strongly affect the surface charge.5, 6 When the effects of brine chemistry are removed, silica tends to adsorb simple organic bases (cationic surfactant), while the carbonates tend to adsorb simple organic acids (anionic surfactant). This occurs because silica normally has a negatively charged weak acidic surface in water near neutral pH, while the carbonates have positively charged weak basic surfaces. Several concerns about the chromatographic separation of the surfactant mixture have been expressed in the literature.7–12 Scamhorn et al.12 showed that adsorption is expected to increase with the surfactant's hydrophobicity at the pre-micellar concentration range of surfactant, since an increase in hydrophobicity tends to drive the surfactant from the aqueous phase to the solid-liquid surface. Mannhardt and Novosod 9 developed a model for adsorption of a surfactant mixture in flow through porous media. They concluded that the chromatographic movement of surfactant mixtures through the porous media depends not only on their affinity for the surface (selectivity), but also on their tendency to form micelles.

The stability of nitrogen gas foam hinders its applicability in petroleum applications. Fly ash nanoparticles and clay improve the N2 foam stability, and flue gas foams provide a cost-effective solution for carbon capture, utilization, and storage (CCUS). This study examines the stability, volume, and bubble structure of foams formed using two anionic surfactants, sodium dodecyl sulfate (SDS) and sodium dodecylbenzene sulfonate (SDBS), along with the cationic surfactant cetyltrimethylammonium bromide (CTAB), selected for their comparable interfacial tension properties. Analysis of foam stability and volume and bubble structure was conducted under different CO2/N2 mixtures, with half-life and initial foam volume serving as the evaluation criteria. The impact of fly ash and clay on SDS-N2 foam was also evaluated. The results showed that foams created with CTAB, SDBS, and SDS exhibit the greatest stability in pure nitrogen, attributed to low solubility in water and limited gas diffusion. SDS showed the highest foam strength attributable to its comparatively low surface tension. The addition of fly ash and clay significantly improved foam stability by migrating to the gas–liquid interface, creating a protective barrier that reduced drainage. Both nano fly ash and clay improved the half-life of nitrogen foam by 11.25 times and increased the foam volume, with optimal concentrations identified as 5.0 wt% for fly ash and 3.0 wt% for clay. This research emphasizes the importance of fly ash nanoparticles in stabilizing foams, therefore optimizing a foam system for enhanced oil recovery (EOR).

Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants

Surfactant enhanced remediation of cadmium contaminated soils

The solubilization behavior of mixed micelles of nonionic and anionic surfactants toward a water-insoluble dye, Yellow OB, has been studied. The surfactants examined were a nonionic surfactant, dodecyl polyoxyethylene ether (C12POE), and anionic surfactants with the chemical structure of (Remark: Graphics omitted.), where m+n=8 and where m or n is 0, 4, or 8 (and sodium decyl sulfonate for reference). The solubilization greatly depends on the position of the benzene ring in the hydrocarbon chain of the anionic surfactant mixed; in the mixture of C12POE and (Remark: Graphics omitted.), the synergistic effect in solubilization is remarkable. The results have been discussed in relation to the structure or compactness of the polyoxyethylene shell of the mixed micelle, and in relation to the interaction of anionic and nonionic surfactants in their mixed micelle, which had previously been observed by NMR measurements.

An investigation involving the addition of surfactant to remediate cadmium-contaminated soils was performed to determine the optimal surfactant enhanced remediation system. Anionic (sodium dodecyl sulfate, SDS), nonionic (Triton X-100, TX100) and cationic (cetyltrimethylammonium bromide, CTAB) surfactants were used to elucidate the extraction efficiency of surfactant. EDTA and diphenylthiocarbazone (DPC) were also added to enhance the extraction efficiencies of surfactants. Moreover, the pH effect was examined to determine the optimal surfactant systems. The addition of anionic and nonionic surfactants can enhance the desorption rates of cadmium, lead and zinc, whereas the addition of cationic surfactant decreased the desorption efficiency of heavy metals. The desorption efficiency was found to increase linearly with the increasing surfactant concentration below critical micelle concentration (CMC) and remained relatively constant above the CMC. Moreover, the addition of EDTA can significantly enhance the desorption efficiency of heavy metals. Cationic surfactant was shown to be a more effective surfactant than nonionic and anionic surfactants in extracting heavy metals under acidic environment. The desorption efficiency of heavy metal in the surfactant/EDTA mixture system was in the order of Cd > Pb > Zn. However, the addition of DPC lowered the heavy metal removals by 2 to 4 times. Also, increasing pH value can decrease the extraction capabilities of nonionic and anionic surfactants. The results of this study demonstrate that surfactant in combination with complexing agents can be effectively used as chemical amendments to flush cadmium-contaminated soil by proper selection of type and concentration of surfactant and complexing agent at different pH values.

Comparative Study Of The Variability In The Compositions And The Effect Of Milling Time On Coal Fly Ash And Wood Fly Ash Nanoparticles

Surfactants can be used to increase the solubility of poorly soluble drugs in water and to increase drug bioavailability. In this article, solubilization of macrolide antibiotic erythromycin is investigated by employing spectrophotometry and tensiometry in micellar solutions of nonionic (Brij56, Brij58, Brij35, Brij30), cationic (cetyltrimethylamonium bromide, CTAB; tetradecyltrimethylammonium bromide, TTAB; dodecyltrimethylammonium bromide, DTAB), and anionic (sodium dodecylbenzenesulfonate, SDBS; sodium dodecylsulfate, SDS) surfactants and then compared. The results showed that irrespective of the surfactant type, the solubility of erythromycin increases linearly with increasing surfactant concentration, as a consequence of association between the drug and micelles. Solubilization capacity has been quantified in terms of molar solubilization ratio (Rm,S), micelle−water partition coefficient (KM), binding constant (K1) between solubilizate monomer and vacant micelle, and the free energy of solubilization (ΔGso) of the drug in the micelles. Cationic surfactants of the same chain length as that of nonionic and anionic surfactants exhibited higher solubilization capacity, probably due to solubilization at the micelle−water interfaces. The order of solubilization powers among nonionic, cationic, and anionic surfactants for erythromycin was found to be Brij56 > Brij58 > Brij35 > Brij30, CTAB > TTAB > DTAB, and SDBS > SDS, respectively. This comparative study can be used to select an appropriate medium for erythromycin solubilization, where nonionic surfactants are advantageous due to their minimal protein binding and retention of their micellar form even after large dilution in blood owing to their very low critical micellar concentration (cmc) values.

Herein, we report a KBr-impregnated paper substrate as a sample probe to enhance the attenuated total reflection-Fourier transform infrared (ATR-FTIR) signal strength of anionic surfactants (AS) and non-ionic surfactants (NS) in an aqueous solution. The mechanism for the sensing of AS and NS is based on the strong interaction of surfactants with the silicate groups (SiO44−) of the KBr-impregnated paper substrate. The role of SiO44− on the surface of the paper is to enhance the adsorption of AS and NS, resulting in improved IR signal intensities for the target analytes. The improved signal intensity at 1253 cm−1 (SO42−, symmetric stretching) for AS and 1114 cm−1 (C–O–C, stretching vibration) for NS were selected for quantification. SEM-EDX was employed to determine the elemental compositions of pre- and post-adsorbed AS and NS on glass fibre filter paper (GFF). The linear range for the determination of AS and NS was 10–100 μg L−1 with a method detection limit (MDL) of 4 μg L−1 and method quantification limit (MQL) of 12 μg L−1. The good relative recovery of 71.4–109.7% and the interference studies showed the selectivity of the method for the determination of AS and NS in environmental water and commodity samples. The advantages of this method include its cost-effectiveness, enhanced sensitivity, disposability and accessibility of the paper substrate.

Wettability alteration in shale formations can be an important factor in improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in Unconventional Liquid Reservoirs (ULR) favoring the process of imbibition. This study evaluates and compares the efficiency of anionic and nonionic surfactants in recovering hydrocarbons in carbonate and siliceous preserved side-wall core. The techniques developed also open the door for investigation of low concentration surfactants for enhanced oil recovery (EOR) in ULR. Contact angle (CA) experiments were performed, using the captive bubble method, to measure the magnitude of wettability alteration on intermediate to oil-wet ULR core at reservoir temperature (165 °F). Different types of anionic and nonionic surfactants at field concentrations were used. The results showed that all surfactants lower the CA at the concentration tested. However, anionic surfactants showed better results as observed by lower contact angles. IFT measurements were also performed, using the pendant drop and spinning drop methods, at reservoir temperature using reservoir crude oil and anionic and nonionic surfactants at the same concentrations. The IFT reduction was similar for each type of surfactant compared to regular frac fluid without any surfactant, but anionic surfactant showed slightly better capability of reducing IFT than nonionic surfactants. Computed tomography (CT) scan methods were used to gauge the performance of these surfactants in improving oil recovery. The magnitude of penetration or imbibition into artificially-fractured ULR cores was studied for both anionic and nonionic surfactants. Frac fluids containing surfactants were mixed with a dopant salt to trace the movement of these fluids and measure the penetration numerically. Both, anionic and nonionic, surfactants have higher penetration magnitudes compared to slick water without surfactant. However, anionic surfactants displaced a higher observable amount of liquid hydrocarbon from the shale cores. This observation agrees qualitatively with the results observed in the CA experiments where anionic surfactants showed the lowest contact angles. From the results obtained, it can be concluded that anionic surfactants alter wettability in these ULR core, giving lower CA, better spontaneous imbibition and higher oil recovery than nonionic surfactants. These observed wettability changes induced by surfactants mixed in the frac fluids can improve matrix penetration with spontaneous imbibition which opens further discussions for EOR potential in shale formations.