Significant Reduction In Interfacial Tension Research Articles

Combined effect of silica nanoparticles and binary surfactants in enhancing oil recovery: An experimental investigation

Modern oil fields extensively utilize enhanced oil recovery (EOR) techniques to optimize production. This investigation evaluates the potential of silica (SiO2) nanoparticles (NPs) when combined with the SDS-TX100/xanthan gum (XG) binary surfactant/polymer mixture for enhancing oil recovery. The study focuses on examining the synergistic effects of the SDS-TX100 + XG combination and SiO2 NPs on reducing interfacial tension (IFT), altering wettability, and improving viscosity. Core flooding experiments were conducted on low-permeability San Saba sandstone cores. The dispersion and stability of SiO2 NPs in the SDS-TX100 surfactant mixture were evaluated through stability analysis, dynamic light scattering (DLS), Ultraviolet–visible spectroscopy (UV–VIS), and turbidity meter. Notably, the NPs exhibited a significant reduction in IFT between the SDS-TX100 surfactant mixture and crude oil, while the addition of the SDS-TX100 surfactant mixture improved the stability of nanofluids. Core flooding experiments revealed a synergistic effect of SiO2 NPs with the SDS-TX100 + XG mixture, leading to higher incremental oil recovery compared to the SDS-TX100 + XG mixture alone. The study elucidates various mechanisms contributing to oil recovery, including wettability alteration and IFT reduction. The flooding outcomes indicate that injecting SiO2 NPs with the SDS-TX100 + XG mixture increases oil recovery by up to 16 % of the original oil in place (OIIP) after conventional water flooding. This research contributes to a comprehensive understanding of the application of SiO2 NPs with binary surfactant and polymer as a chemical-EOR (CEOR) agent and assists in identifying sandstone reservoirs where nanofluids could be effectively deployed.

Impact of cationic surfactant-coated hydrophilic nanoparticles on polymeric solution performance in chemical enhanced oil recovery (CEOR) from a two-dimensional porous medium

This study aims to investigate the mechanisms underlying enhanced oil recovery (EOR) through chemical injection and explore the key parameters influencing these mechanisms in a two-dimensional porous medium. Distilled water, polyacrylamide (PAM), α-Al2O3 nanoparticles, and cetyltrimethylammonium bromide (CTAB) surfactant were employed for this purpose. The effects of interfacial tension (IFT), viscosity, and zeta potential measurement were also examined. The results revealed that the injection of PAM polymer increased the viscosity of the displacing fluid, and enhanced the sweep efficiency. This resulted in a 35 % increase in the oil recovery factor compared to the water injection alone. Furthermore, the introduction of alumina (α-Al2O3) nanoparticles altered the wettability and stabilized the emulsion, leading to a further increase in the oil recovery factor. In the optimal state, the oil recovery factor reached 63.2 %. Moreover, the study of various concentrations of polymer and nanoparticles illustrated that low concentrations of polymer and high concentrations of nanoparticles in the base fluid resulted in higher oil recovery factors. Furthermore, adding CTAB surfactant ended a significant reduction in IFT, with a decrease from 45.03 to 10.33 mN/m. This reduction resulted in the highest oil recovery factor of 69 %. Consequently, the highest oil recovery factor was achieved using PAM polymer at a concentration of 500 ppm, α-Al2O3 nanoparticles at a concentration of 0.1 wt%, and CTAB surfactant at a critical micelle concentration of 1 mM in the base fluid (pure water), with a constant injection flowrate of 0.1 ml/min.

Molecular dynamics simulation of oil displacement using surfactant in a nano-silica pore

Molecular Dynamics (MD) simulations of oil droplet displacement have been performed using pressure driven surfactant flooding at a typical reservoir condition (T=330 K and P=20 MPa). The behavior of the micellization of surfactant molecules has been validated. A micelle with a radius of 22.85 Å is formed by 60 anionic sodium dodecyl benzenesulfonate (SDBS) surfactant molecules in aqueous solution. Surfactant additions result in significant reduction of interfacial tension (IFT) for oil/water system and such reduction is dependent on surfactant surface concentration. The microscopic mechanism of IFT reduction is described. Interfacial thickness increases from 3.5 Å to 22.5 Å at T=300 K andP=1 atm after surfactant molecules are adsorbed at oil/water interface, indicating high miscibility of two phases and thus results in interfacial tension reduction; the calculated interface formation energy of a single surfactant molecule is −145.7 Kcal/mol, which means the additions of surfactant would lead to the decrease of system energy and thus a more steady system. For surfactant flooding simulation, oil droplet static contact angle increases with surfactant additions. The larger the static contact angle of oil droplet, the stronger the drop deformation and the higher the displacement speed. Limited deformation is observed as oil droplet detaches from the solid substrate. Compared with water flooding, surfactant additions can significantly increase oil displacement speed by up to 80 %.

A New Approach to Recycling PET Bottles by Blending Polyethylene- Terephthalate and HDPE Using Chemical Reactions in One Step Process

The overall goal of this study is to propose a new approach to simplify the recycling process for producing high quality material from the waste of beverage bottles and other sources at a lower cost by using mechanical recycling and chemical reactions inside injection molding machines in a one-step process. The water and soft drink bottles are made of PET material, while the caps are made mainly of HDPE. The blends of PET and HDPE are incompatible. The resulted material has poor mechanical properties due to the immiscibility of polymer blend components, phase separation, and lack of interfacial adhesion. (HDPE-g-MA) was found to be an excellent reactive compatibilizer for the PET/HDPE blend. For the purpose of investigating the mechanical and morphological properties in this study, blends of rPET and virgin HDPE in weight compositions of 80/20, and 60/40 were modified with concentrations of 2 and 5 wt percent of (HDPE-g-MA). The addition of 4,4-Methylenebis (phenyl isocyanate) and compatiblizer increased the viscosity and molecular weight of the blends while also improving miscibility and interaction bonds between molecules, resulting in a significant reduction in interfacial tension and improved phase dispersion and adhesion via interpenetration and entanglements at the interface. The rPET segments have been grafted onto HDPE backbone chains. Since the crystallinity of HDPE is low, the crystallinity and crystallization temperature of rPET in the blends were reduced. The mechanical characteristics were improved by achieving uniform phase morphology. The main finding of this study is that the immiscible rPET/HDPE materials can be treated and processed in a single step inside the injection molding process. The one-step process is sufficient because it shows high improvement in the mechanical characteristics, while the two-step process, namely the extrusion followed by injection molding, improves fewer mechanical characteristics and is more expensive.

Effect of surface functionalized silica nanoparticles on interfacial behavior: Wettability, interfacial tension and emulsification characteristics

Due to their unique properties, nanoparticles have recently attracted lots of attention for enhanced oil recovery (EOR) and CO2 geo-sequestration (CGS) applications. The purpose of this research is to offer a better understanding of the role of nanoparticles on interfacial phenomena with a special focus on wettability alteration, interfacial tension and emulsification characteristics. Contact angle measurements were used to explore the effect of nanoparticles on wettability alteration of glass surfaces using sessile drop method in the absence and presence of NaCl. Scanning electron microscopy (SEM) images were collected to visualize how nanoparticles change the wettability of the surfaces. The effect of different parameters on morphology variation of glass surfaces and the consequent wettability alteration was examined. The investigated variables were nanoparticle concentration, exposure time, measurement time and salinity. Next, the effect of nanoparticles on interfacial tension (IFT) between water and n-octane was studied via the Wilhelmy plate method. The effect of nanoparticle concentration on IFT was investigated with and without added NaCl. Finally, a series of simple batch experiments were conducted to observe the effect of nanoparticles in emulsification behavior of a water-n-octane system. Photography and optical microscopy images were collected to analyze the stability and morphology of the formed emulsions for different nanoparticle concentrations in the absence and presence of NaCl.Our results show that the EOR-12 nanoparticles have excellent water-wetness properties and emulsification characteristics but do not necessarily change the IFT in a water-n-octane system.micrographs taken from the nanofluid-treated glass surfaces showed a thick coverage of nanoparticles confirming the adsorption of nanoparticles onto the surface. Additionally, SEM images revealed a topography change of surfaces from smooth to rough after treatment with nanofluid which is the responsible mechanism for the observed wettability alteration. The higher the exposure time, the rougher the nanoparticle adsorption layer and consequently the better the performance of nanoparticles in wettability alteration of glass surfaces. Additionally, up to a threshold concentration, the contact angle decreased as the nanoparticle concentration increased, but above the threshold concentration, the measured contact angle did not show remarkable reduction. Conducting contact angle measurements in the presence of NaCl demonstrated that salinity can increase the adsorption rate, the final number of nanoparticles on the glass surface, the surface roughness and the intrinsic contact angle of nanoparticles leading to a better water-wetness. Testing different concentration of nanoparticles demonstrated that in the presence of NaCl, the wettability of the glass surface was not affected by the concentration and low concentrations of nanoparticles act as good as high concentrations.IFT measurements did not show any significant reduction in IFT between water and n-octane for all the tested concentrations with and without added NaCl mainly because of lack of the energy required to bring the nanoparticles at the interface.The results of batch emulsification experiments revealed that EOR-12 nanoparticles could serve as highly efficient Pickering emulsifiers in terms of both initial emulsion volume and its stability over time with and without NaCl. Adsorption of the nanoparticles at the interface was identified as the underlying mechanism for the emulsification characteristics of the nanoparticles. Photographs and optical microscopy measurement results illustrated that by tuning the nanoparticle concentration, emulsion droplet size and its uniformity can be adjusted. By utilizing higher concentrations of nanofluid, emulsions with smaller and more uniform droplet size and higher stability can be created.

Effects of zero-shear rate viscosity and interfacial tension on immiscible Newtonian-Non-Newtonian fluids morphology in radial displacement inside the Hele-Shaw cell

We report on experimental study of interfacial instability in immiscible Newtonian-Non-Newtonian radial displacement occurs in Hele-Shaw cell where liquid paraffin was injected to displace carboxymethyl cellulose (CMC) solution. For the benchmark system, tip-splitting pattern was observed. Results indicated that the maximum change in the shear rate and viscosity of CMC solution occurs in the very early stage of the displacement process. The comparison between Newtonian-Non-Newtonian and Newtonian-Newtonian interfacial development, showed higher number of fingers for Newtonian displacement, but wider and longer fingers for non-Newtonian system. Investigation of concentration effect indicated that the interfacial instability decreased in displacing of 0.5%wt CMC solution. In contrast with literature, the instability increased significantly for 1.5%wt CMC solution, and dendritic pattern emerged instead of tip-splitting. This was due to the significant reduction in interfacial tension and rise in viscose forces. Moreover, the results showed that increasing the initial injection radius led to increment in fingers number and reduction in velocity of the dominant fingertip. Additionally, increasing the injection flowrate resulted in fingering pattern change from tip-splitting to dendritic type. Finally, comparing the number of the observed fingers with literature, suggested that using average capillary number; Ca ≤ 10−3, Paterson's theory may be followed by the experimental results.

THE EFFECT OF HARDNESS AND TEMPERATURE ON INTERFACIAL TENSION OF INDIVIDUAL AND MIXED SURFACTANT SYSTEM

Surfactant flooding is one of the chemical enhanced oil recovery (CEOR) techniques that can be used to improve oil recovery. The surfactant injection reduces the oil-water interfacial tension and mobilizes residual oil towards the producing well. In this paper, the performance of alkyl ether carboxylate (AEC) and calcium lignosulfonate (CLS) in individual and mixed surfactant systems were investigated based on their ability to reduce the interfacial tension through a spinning drop method. The interfacial tensions of individual and mixed surfactant systems in different brine systems were measured against decane at 25°C and 98°C. The results show that the individual and mixed surfactant systems in 3.5 wt.% NaCl brine has a significant reduction in interfacial tension at 98°C. In contrast, the presence of hardness in 2.5 wt.% NaCl and 1.0 wt.% MgCl2 brine reduces the interfacial tension of the individual AEC surfactant system and mixed surfactant system significantly at 98°C except for the individual CLS system. Meanwhile, the interfacial tension of mixed surfactant system decreases with increasing surfactant concentration in two brine systems and at 98°C. The findings show the significant application of the AEC and CLS surfactant mixture considering the harsh reservoir conditions for the chemical enhanced oil recovery application.

Effect of interface elasticity on improved oil recovery in a carbonate rock from low salinity and ultra-low concentration demulsifier

The increase in oil recovery from low salinity water injection has been often attributed to the alteration of wettability to water wetting. The increase in elasticity of the interface may also contribute to increase in oil recovery as has been suggested in the literature.In this work, we investigate oil recovery using two carbonate cores, one with large vugs, and the other without. The pore size and pore size distributions are very different in the two carbonate cores. The investigation centers on oil recovery from low and high salinity water injection, and by addition of an effective demulsifier molecule at 100 ppm in the injected high salinity water. The effective demulsifier molecule gives substantially higher oil recovery than low salinity and high salinity water injection. The oil-water interface elasticity increases significantly from the addition of 100 ppm demulsifier molecule to the aqueous phase. Salinity of the injected water is found to have a weak effect on oil recovery. We attribute high recovery performance of the 100 ppm surfactant to the increase in interface elasticity. The high recovery performance is observed in the carbonate reservoir rocks, both with and without vugs. The demulsifier molecule which is non-ionic has a very low adsorption in the carbonate rocks, around 2 mg/g at 100 ppm in high salinity injection water.This work introduces a new process for improved oil recovery by the introduction of a demulsifier molecule at ultra-low cocentration. The molecule has limited effect on water-wetting. The critical micelle concentration (CMC) of the non-ionic surfactant in the injected brine is at 30 ppm. The low adsorption, and the CMC indicate that the molecule adsorbs at the oil-water interface. The conventional chemical flooding which may require one or two orders of magnitude more material is through significant reduction of interfacial tension. The interface elasticity is singled out to be the main contribution to improved oil recovery in this work.

Experimental investigation of the effect of green TiO2/Quartz nanocomposite on interfacial tension reduction, wettability alteration, and oil recovery improvement

Nanoparticles (NPs) have shown showed a promising role in improving oil recovery as potential enhanced oil recovery (EOR) agents. In this study, one-pot green technique was used to synthesize titanium oxide NPs from the euphoria condylocarpa extract, and graft it on the surface of quartz to develop a green nanocomposite (NC) for enhanced oil recovery (EOR) applications. The synthesized TiO2/Quartz NC was identified using X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM). In order to prepare the novel nanofluids, the synthesized NC was dispersed in desilted water, seawater and low-salinity water (seawater dilution), which were characterized through analyzing their stability, viscosity, pH, density and conductivity behaviors. The prepared nanofluids were used to minimize the interfacial tension (IFT) and contact angle between crude oil and water on the surface of carbonate rocks. The obtained results show that TiO2/Quartz-nanofluid (DWN1000), with 1000 ppm dispersed in distilled water, enables an additional oil recovery of 21% OOIP due to a significant reduction in IFT from 36.4 to 3.5 mN/m, improving the rheology behavior and wettability alteration towards a stronger water-wet system from 103° to 48° contact angle. Thus, the synthesized NC provides high stability solution with a promising potential in EOR applications.

Synergistic influence of nanoparticles and surfactants on interfacial tension reduction, wettability alteration and stabilization of oil-in-water emulsion

In this study, the synergistic interaction of nanoparticles and surfactants were explored for oil-water interfacial tension (IFT) reduction, alteration of rock wettability, and stabilization of oil-in-water emulsion. The interfacial properties were investigated using drop-shape analyzer (DSA 25) while the pore scale visualization studies were conducted using the etched glass micromodels. The most stable surfactant-stabilized emulsion was formed in presence of cetyltrimethylammonium bromide (CTAB) while the order of increasing emulsion stability in presence of nanoparticles was obtained as follows: carbon nanotubes >copper oxide> silicon dioxide> aluminum oxide > titanium dioxide. Compared to pure nanofluids or surfactant solutions, the nanoparticles-surfactant solutions demonstrated promising tendency for significant reduction in oil-water interfacial tension and alteration of rock wetting properties. Specifically, the carbon nanotubes (CN) based nanofluids, reduced the contact angle of the rock from 68.73° to 65.5° (4.7%) while the Triton X-100 (TX 100) and CN-TX100 solutions reduced the contact angles to 10.65° (84.5%) and 7.0° (89.8%) respectively. The dominant mechanism of resident oil mobilization from the micro and dead-end pores was identified as emulsification-entrainment. A correlation exists between influence of nanoparticles-surfactant solutions on interfacial properties and resident oil mobilization from the micro and dead-end pores. The CN-CTAB solution that was the most effective in mobilization of the resident oil from the micro and dead-end pores significantly reduced the crude oil-water IFT to 0.63 mN/m. The mechanisms of IFT reduction, wetting properties alteration, as well as emulsion stabilization have been identified as the orientation of the particles at the interface and the electrostatic interaction between the nanoparticles and surfactant molecules. These procedures could be exploited to achieve significant reduction in IFT, rock wettability alteration and emulsion stabilization than could be achieved using pure nanofluids or surfactant solutions only.

Favorable attributes of low salinity water aided alkaline on crude oil-brine-carbonate rock system

Although low-salinity water flooding (LSWF) is an enhanced oil recovery (EOR) method, it does not target weakly water-wet situation (which is the best situation for the EOR process) for carbonate rocks. Also, this method does not show a significant reduction in the oil-water interfacial tension (IFT). Despite the ability of alkaline flooding to alter the rock wettability to the desirable range as well as a signification reduction in IFT, the need for a high amount of alkaline makes the approach economically unjustified. In the current study, favorable attributes of low salinity water aided alkaline (LSWA) approach on a crude oil/brine/carbonate rock (CBR) system are presented in terms of IFT reduction and contact angle (CA) alteration. To this end, three solutions with different alkalinity (weak (NaHCO3), intermediate (Na2CO3), and strong (NaOH)) degrees are used in combination with different LSW. The results show that LSWA achieves the target wettability range (75-85°). Also, the reaction between divalent ions with an alkaline solution is an unfavorable factor on the rock surface. As a considerable achievement, the LSWA approach resulted in a significant reduction in IFT, which was reduced from 13.2 mN/m to 1.1 mN/m in the LSW approach by adding 4000 ppm of NaOH. Therefore, using the LSWA flooding in enhancing oil recovery (EOR) from carbonate reservoirs is highly recommended to get a higher efficiency at a lower concentration of alkaline, which leads to a decrease in costs.

Synergistic effects of nanoparticles and surfactants on n-decane-water interfacial tension and bulk foam stability at high temperature

The synergistic effects of nanoparticles and surfactants on decane-water interfacial tension, and bulk foam stability at high temperature was investigated in this study. The interfacial properties were determined using a spinning drop interfacial tensiometer while the foam stability was evaluated from the normalized foam height. The extent of interaction between nanoparticles and surfactants was estimated from the hydrodynamic nano-aggregate sizes and zeta potential values. The foam microscopic images and the bubble morphology were examined to elucidate the mechanisms of foam stabilization by nanoparticles. Results clearly showed that nanoparticles-Triton X-100 mixed system demonstrated the smallest aggregate sizes in bulk solution and considerable reduction in water/n-decane interfacial tension. Significant reduction in interfacial tension and increased foam stability occurred due to electrostatic interaction between the charged surfaces of the nanoparticles and surfactant head-groups. However, influence of electrostatic attraction was found to be dominant over the influence of electrostatic repulsion in promoting foam stability and reducing interfacial tension. The most stable foam was generated by titanium dioxide (TiO2) nanoparticles and cetyltrimethylammonium, bromide (CTAB), while the least stable foam was generated in presence of multi-walled carbon nanotubes and triton X-100. Possible reasons and mechanisms for these observations were suggested. The destabilizing influence of high temperature on foam stability was significant, however, CTAB-foam stability increased by 160% and 440% in presence of silicon dioxide (SiO2) and TiO2 nanoparticles at 80 °C. This phenomenon can be attributed to the moderate adsorption and aggregation of surface-active complex at the gas-liquid interface of the foam and Plateau borders.

Potential application of low-salinity polymeric-nanofluid in carbonate oil reservoirs: IFT reduction, wettability alteration, rheology and emulsification characteristics

Polymer and low-salinity water flooding have been shown, repeatedly, to be effective methods for chemical Enhanced Oil Recovery (cEOR). The benefits are obtained by increasing the viscosity of the injected fluid, minimizing the interfacial tension (IFT) of the crude oil/aqueous phase, and by wettability alteration. Similarly, nanofluids (fluids injected with nanoparticles) have also been demonstrated to induce the same processes. We have analyzed the EOR response of green nanofluids when formulated with a typical natural polymer mixed with low salinity water. For this purpose, a polymer coated ZnO/SiO2 nanocomposite (NC) has been produced from the pomegranate seed extract using a simple, economical and, importantly, green method. The characterization of the synthesized NC has been investigated using the scanning electron microscopy (SEM), electron dispersive spectroscopy (EDS), and X-ray diffraction (XRD). The polymeric nanofluids were then tested in various experimental studies related to the stability of injected fluids, IFT behavior, wettability alteration, oil/nanofluid emulsification, and EOR flooding dependent on the NC concentration, time and salinity. The low salinity-polymeric nanofluid (LPN), with 2000 ppm NC concentration, enabled higher oil recovery by about 19.28% OOIP due to a significant reduction in IFT, higher viscosity, better emulsion stability, and wettability alteration towards a stronger water-wet system from 137° to 34° contact angle.

Inhomogeneity of block copolymers at the interface of an immiscible polymer blend

We present the effects of structure and stiffness of block copolymers on the interfacial properties of an immiscible homopolymer blend. Diblock and two-arm grafted copolymers with variation in stiffness are modeled using coarse-grained molecular dynamics to compare the compatibilization efficiency, i.e., reduction of interfacial tension. Overall, grafted copolymers are located more compactly at the interface and show better compatibilization efficiency than diblock copolymers. In addition, an increase in the stiffness for one of the blocks of the diblock copolymers causes unusual inhomogeneous interfacial coverage due to bundle formation. However, an increase in the stiffness for one of blocks of the grafted copolymers prevents the bundle formation due to the branched chain. As a result, homogeneous interfacial coverage of homopolymer blends is realized with significant reduction of interfacial tension which makes grafted copolymer a better candidate for the compatibilizer of immiscible homopolymer blend.

Influence of Organic Acid and Organic Base Interactions on Interfacial Properties in NAPL−Water Systems

Interfacial properties play an important role in determining the transport and distribution of waste nonaqueous phase liquids (NAPLs) in groundwater. To develop a better understanding of the solute interactions governing the interfacial properties of waste NAPLs, this study examined the interfacial tension and contact angle of a tetrachloroethylene/water/quartz system containing octanoic acid and dodecylamine as a function of pH. The results showed that interactions between these solutes affected the system's interfacial properties significantly, producing a positive synergism. For example, octanoic acid, which by itself does not affect wettability, could reverse the wettability of quartz in the presence of dodecylamine. The significant reduction in interfacial tension and increase in contact angle around neutral pH was, based on the results of speciation modeling, attributed to the formation of a complex composed of the protonated organic base and deprotonated organic acid, whose formation also peaks around neutral pH. Thus, measures of the content of only one class of compounds, such as the base number, are inadequate descriptors of a NAPL's ability to alter wettability.

The interfacial tension and morphology of reactive polymer blends

Interfacial tension and morphology of polyamide6 (PA6) and polypropylene (PP) blends containing polypropylene grafted with maleic anhydride (PPMAH) as reactive compatibilizer were studied by Neumann Triangle method, Scanning Electron Microscopy and Transmission Electron Microscopy. It was observed that there was a significant reduction of interfacial tension due to the in situ formed copolymer at the interface acting as an emulsifier, and there was a limiting value of the interfacial tension under a saturation concentration of compatibilizer ( C saturation) at which the interface was saturated by the in situ formed copolymer. For the morphology, there was also a critical concentration of the compatibilizer ( C critical). For decreasing the size of the dispersed phase, there was no further decrease in the dispersed particle size above C critical. The areal density of the in situ formed copolymer ( Σ critical) was estimated, and it was concluded that to emulsify the PA6/PP blend, 100% coverage of the interface by the in situ formed copolymer was not required; up to 63.7% coverage of the interface is sufficient.

Energized Fracturing With 50% CO2 for Improved Hydrocarbon Recovery

Summary For several years, carbon dioxide (CO2) has been added to fracturing fluids at concentrations of 100 to 500 cu ft/bbl (18 to 90 m3/m3) to assist in post-treatment cleanup. In some instances, this has eliminated swabbing after treatment. A recent technique increases the concentration of liquid CO2 to 50% of the total injected volume, approximately 3,000 cu ft/bbl (540 m3/m3). Distinguishing features of this technique are improved fluid-loss control, higher injection rates, increased proppant concentrations, faster fluid recovery, and improved production. Introduction Since the early 1960's, liquefied CO2 has been used widely as an additive to hydraulic fracturing and acid treatments to improve recovery of treating fluid. CO2 may exist as liquid, gas, or solid (Fig. 1). It has a critical temperature of 87.8 degrees F (31 degrees C) and a critical pressure of 1,071 psia (7.4 MPa). During a fracturing treatment, the liquefied CO2 nominally is injected below critical temperature and remains liquid until heated. After CO2 enters the perforations, it may expand into a gaseous state, which provides improved fluid-loss control. The injected liquid CO2 flows back as gas after treatment, along with some fracturing and formation fluids. Mechanism of Fracturing With High CO2 Concentrations When the liquid CO2 is commingled with gelled water, the mixture remains liquid until heated to the critical temperature of 87.8 degrees F, when CO2 begins to vaporize. Even at high temperatures, the solubility of CO2 in water remains high (Fig. 2). 1 This property is a big advantage in recovering the fracturing fluid. It provides a long-sustained solution-gas drive. Fig. 3 shows the high solubility of CO2 in crude oil. The CO2 that goes into solution in a crude oil also imparts a solution-gas drive to the affected fluids when pressure is reduced. Fig. 4 shows that CO2 reduces the viscosity of formation crude oils. Although the amount of CO2 that enters the formation during the fracturing treatment is probably insufficient to reduce oil viscosity deep in the reservoir, the injected CO2 may contact the formation oil near the created fracture. This can reduce oil viscosity in this vicinity and, thereby, improve cleanup after treatment. Fluid retention in a formation is related to interfacial tension of fluids in the reservoir and capillary effects. Fig. 5 shows a significant reduction in interfacial tension when water is saturated with CO2 under pressure. Simon et al. reported interfacial tensions of CO2 with crude oils above saturation of less than 2 dyne/cm (2 mN/m) at 3,000 psi (20.8 MPa). A decrease of 30 to 40% in interfacial tension in laboratory experiments was reported when water was saturated with CO2. Reductions in interfacial tension aid capillary flow of fluids in the minute pores in the formation and help prevent water blocks. The use of high CO2 concentrations reduces the amount of water injected and, consequently, the amount retained in the formation. This significantly decreases water volume injected, water/clay contact time, and cleanup time after treatment. Comparison of CO2 With Other Energized Fracturing Fluids Other energized fluids such as nitrogen, liquefied petroleum gas mixed with CO2, and stable (50 to 80% nitrogen) foams have been used successfully as fracturing fluids. Liquefied petroleum gas has been eliminated as a viable fracturing energy gas because of its flammability. JPT P. 135^