Nonionic Surfactant for Enhanced Oil Recovery from Carbonates: Adsorption Kinetics and Equilibrium

Orange Mesocarp Extract as a Natural Surfactant: Impact on Fluid-Fluid and Fluid-Rock Interactions during Chemical Flooding

Surfactant flooding has suffered a huge setback owing to its cost and the ecotoxic nature of synthetic surfactants. The potential of natural surfactants for enhanced oil recovery has attracted a great deal of research interest in recent times. In this research, orange mesocarp extract (OME) was studied as a potential green surface-active agent in recovering heavy oil. The extract obtained from the orange (Citrus sinensis) mesocarp using alkaline water as solvent was characterized by Fourier transform infrared spectrophotometry . Phase behavior was studied to ascertain its stability at 100 °C and compatibility with divalent ions. Microemulsion system, interfacial tension, optimal salinity, and critical micelle concentration were analyzed to evaluate the surfactant. Oil displacement analysis using an oil-wet sandstone medium under reservoir conditions was performed. Surfactant adsorption mechanism on the core was investigated at atmospheric conditions (28 °C) using the Langmuir, Freundlich, Temkin, and linear isotherm models, while the kinetics pattern was modeled with the pseudo-first-order, pseudo-second-order, intraparticle diffusion, and Elovich models. Results showed fluid compatibility and bicontinuous microemulsion at varied temperatures. Surfactant flooding produced an additional oil recovery of 44 and 29.1%, which confirms the capability of this natural surfactant in recovering heavy oil. Langmuir isotherm gave the highest correlation coefficient (R2) value of 0.982, indicating that the adsorption of the surfactant (OME) on the core occurred at specific homogeneous sites, which when occupied by a higher surfactant concentration will disallow further adsorption on these sites. From the R2 values, almost all of the kinetic models corroborated good adsorption capacity of the core and an affinity for the surfactant at low concentration. This indicates that low concentration of the surfactant may not favor the enhanced oil recovery operation due to adsorption in the reservoirs, hence the need to flood at a higher surfactant concentration.

Examination of the Factors Inhibiting CO2 Adsorption on Coal: A Case Study from Shallow-Depth Low-Rank Coal Seams

Understanding the inhibitory factors affecting the adsorption of CO2 on low-rank coal from shallow-depth coal seams is essential to identify potential coal seams for CO2 sequestration. The CO2 adsorption capacity of shallow-depth coals was measured at a low pressure on raw and dry coals. The samples were also prepared for organic analyses, scanning electron microscopy analyses, and low-temperature nitrogen adsorption analyses to evaluate the CO2 adsorption and identify the inhibitory factors. An investigation was conducted to determine how CO2 adsorption occurs on coal by fitting experimental data to adsorption isotherm models, followed by analyzing the results based on the statistical analysis. In addition, this study used Henry's law, surface potential, and Gibbs free energy to identify the adsorption inhibitor between CO2 and coal. The CO2 adsorption experiment was conducted on raw coal with a moisture content of 15.18-20.11% and dry coal with no moisture. The experimental data showed that the CO2 adsorption capacity in dry coal was 1.6-1.8 times greater than that in raw coal. A fitting graph between the adsorption data and the isotherm model indicated that CO2 adsorption on coal occurred on monolayers and multilayers under raw and dry conditions. Statistical evaluation of the adsorption isotherm models showed that the Langmuir and Freundlich models aligned more closely to the experimental data. According to this result, low-pressure adsorption of CO2 on coal occurred in monolayers and multilayers under raw and dry conditions. Coal containing a high huminite content had a higher potential for CO2 adsorption, and the drying increased the positive relationship. On the other hand, coal containing high inertinite content inhibited CO2 adsorption onto the coal, but the drying process did not adversely affect CO2 adsorption. Furthermore, coal with high moisture and inertinite content inhibited the affinity, accommodation, and spontaneous CO2 adsorption onto the coal. CO2 adsorption could lead to swelling, but moisture loss opened more sites and micropores, resulting in the swelling effect not closing all micropores in dry coal. Based on these results, coal seams with low moisture and inertinite content are the most promising for CO2 adsorption. Altogether, this study provides an understanding of the percentage of inhibitor factors that affects CO2 adsorption on low-rank coal from shallow depths, which may lead to different CO2 adsorption capacities.

Investigation of the Nonionic Acidizing Retarder AAO for Reservoir Stimulation

In the process of matrix acidizing, reducing the reaction rate between hydrochloric acid and carbonate rock to increase oil and gas production has become one of the biggest challenges in reservoir stimulation. An adsorption film formed on rocks can effectively postpone the contact between the hydrogen ion and rock, which is of great significance in decreasing the rate of an acid-rock reaction. In this study, nonionic acidizing retarder AAO was synthesized by acrylamide, allyl poly(ethylene glycol), and octadecyl methacrylate. The structure of AAO was characterized by Fourier transform infrared (FT-IR) spectrometry and 1H nuclear magnetic resonance (1H NMR). The reaction of AAO retard acid and 20% hydrochloric acid with CaCO3 was studied at 50 °C, and the amount of CO2 generated at different times was recorded. The etching time of 0.8% AAO retard acid to CaCO3 could be up to 120 min, whereas 20% hydrochloric acid (without AAO) ended at 45 min, which showed that AAO had the potential to defer the acid-rock reaction. The adsorption behavior of AAO on CaCO3 matched the pseudo-second-order kinetic model well. Meanwhile, the addition of urea greatly reduced the adsorption amount of AAO on CaCO3, which showed that the hydrogen bond was the driving force for the adsorption process. Additionally, the results of X-ray photoelectron spectroscopy (XPS) showed that the N element from acrylamide appeared on the surface of CaCO3 after adsorption. Scanning electron microscopy (SEM) demonstrated that a smooth and dense thin film existed on the surface of CaCO3 treated with AAO retard acid. The change in the vibration peak of C=O from 1720 to 1650 cm-1 indicated that the ester groups in AAO had been hydrolyzed, which was beneficial to film desorption and the reduction of reservoir damage. Therefore, this paper could help with research on carbonate acidizing for reservoir stimulation.

Experimental Investigation on Spontaneous Imbibition of Surfactant Mixtures in Low Permeability Reservoirs

Spontaneous imbibition of surfactants could efficiently enhance oil recovery in low permeability sandstone reservoirs. The majority of studies have considered the application of individual surfactants to alter wettability and reduce interfacial tension (IFT). However, a significant synergistic effect has been reported between different types of surfactants and between salts and surfactants. Therefore, this study systematically studied the capability of a binary surfactant mixture (anionic/nonionic) and a ternary surfactant mixture (anionic/nonionic/strong base-weak acid salt) in imbibition enhanced oil recovery (IEOR). The interfacial properties and the cores' wettability were explored by IFT and contact angle measurements, respectively. Subsequently, the imbibition performances of different types of surfactant solutions were discussed. The results suggested that the surfactants' potential to enhance oil recovery followed the order of ternary surfactant mixture > binary surfactant mixture > anionic > nonionic > amphoteric > polymer. The ternary surfactant mixture exhibited strong capacity to reverse the rock surface from oil-wet (125°) to strongly water-wet (3°), which was more significant than both binary surfactant mixtures and individual surfactants. In addition, the ternary surfactant mixture led to an ultralow IFT value of 0.0015 mN/m, achieving the highest imbibition efficiency (45% OOIP). This research puts forward some new ideas on the application of the synergistic effects of surfactants in IEOR from low-permeability sandstone reservoirs.

Janus Nanoparticle and Surfactant Effects on Oil Drop Migration in Water under Shear

The effects of surface-active nanoparticles and surfactants on the behavior of oil-water interfaces have implications for a variety of industrial processes related to multiphase flows including separation processes, enhanced oil recovery, and environmental remediation. In this work, the migration of an oil droplet in shear flow is investigated with the presence of surface-active molecules and nanoparticles at the oil-water interface. Pure oil (heptadecane) in water and oil with the presence of Janus nanoparticles (JPs) and/or octaethylene glycol monododecyl ether, a nonionic surfactant, were examined using coarse-grained computations. The shear flow field was created utilizing a Couette flow, where the top wall of a channel moved with a specified velocity and the bottom wall was kept stationary. The dissipative particle dynamics (DPD) method was applied. The oil drop was placed on the stationary wall, and its displacement was recorded over time. When surfactants were added at the oil-water interface, the slip of the water over the oil drop was reduced, leading to a larger displacement of the drop. Moreover, surfactant molecules tended to concentrate toward the rear side of the oil drop rather than the front as the drop moved in the flow field. The presence of only JPs on the oil-water interface resulted in slower droplet migration. In the presence of both JPs and surfactants, the effect of JPs on the oil-surfactant-water system was investigated by changing the number of JPs on the drop surface while keeping the concentration of the surfactant constant. Under the same shear rate, the droplet's migration speed increased in the presence of both surfactants and JPs compared to the case of bare oil. The JPs appeared to follow a repeated pattern of motion while residing close to the solid substrate-oil drop contact line. These findings elucidate the contribution of both surfactants and JPs on oil drop displacement for enhanced oil recovery or remediation of an oil-contaminated subsurface.

Application of α-MnO2 nanoparticles for residual oil mobilization through surfactant polymer flooding

Injection of surfactant and polymer slug is among the most effective chemical enhanced oil recovery processes. The only problem encountered with the surfactant polymer (SP) flooding is the loss of surface-active agents that reduce the efficiency of surfactants in the chemical slug. Various attempts to modify SP flooding have been made previously so that the surfactant loss due to adsorption could be reduced. Nanoparticles (NPs) are one of the most effective ways of reducing surfactant adsorption as surfactant particles are held in the liquid phase by nanoparticles, resulting in lower surfactant losses due to adsorption. However, the high cost of the NPs limits their use on the field scale. To encounter this problem, the present study focuses on the application of the manganese dioxide NPs, synthesized through a green route that is economically viable. These NPs are found to be cost-effective as compared to commercially available NPs as well as the synthesis of these NPs does not require the use of toxic chemicals. The 1000 ppm NPs effectively reduced the surfactant adsorption by 46%. The surface tension was lowered from 29.4 to 26.1 mN/m when 1000 ppm NPs were applied to 2500 ppm surfactant solution. Also, the nanoparticles were found to increase the viscosity of the chemical slug by increasing the solid particles present in the slug. The sand pack flooding experiments were carried out to assess the crude oil mobilization ability of the NPs assisted SP flooding. The oil recovery was found to increase from 5% of the original oil in place, resulting in ~ 75% of the crude oil recovery, which was only ~ 70% when NPs were not introduced into the system.

Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

To minimize environmental impact and costs, natural surfactants are suggested as an ecologically sustainable replacement for synthetic surfactants. The aim of this work is to evaluate the efficiency of low-cost saponin-based natural surfactant (SBNS) from Vernonia amygdalina (VA) leaves for enhanced oil recovery (EOR). Furthermore, the study investigated the IFT behaviour of SBNS at oil-water interface and the emulsion behaviour and oil displacement efficiency of SBNS. The SBNS was obtained via ultrasonic extraction of dried VA leaves in a water bath, centrifuging the obtained liquid mixture and freeze drying to evaporate to dryness. Thereafter, Fourier-transform infrared spectroscopy (FTIR) and high-performance liquid chromatography were used to characterize the extracted SBNS. Moreover, tensiometer (Easy-Dyne KRUSS) was used to study the interfacial tension (IFT) behaviour of the SBNS at oil-water interface. Also, the SBNS ability to form stable emulsion in the presence of crude oil was determined. Finally, oil displacement by SBNS solution was investigated under simulated reservoir conditions (3000 psi and 100 °C) with high-pressure high-temperature (Fars EOR) core flooding equipment. The performance of SBNS was compared to commercial non-ionic surfactant 4-octylphenol polyethoxylated (TX-100). Experimental result indicated that the SBNS reduced the IFT at oil-water interface. The natural surfactant lowered the IFT of the oil-water interface from 18.0 to 0.97 mN/m. Moreover, emulsions formed with SBNS showed good stability characterized by a decrease in the median drop diameter with an increase in SBNS concentration. Finally, oil displacement test shows that oil recovery of TX-100 and SBNS increased by 9% and 15% original-oil-in-place (OOIP), respectively. Hence, SBNS is recommended as an appropriate substitute for conventional surfactant due to its inexpensive raw material, lower toxicity, and higher efficiency.

Role of Ionic Headgroups on the Thermal, Rheological, and Foaming Properties of Novel Betaine-Based Polyoxyethylene Zwitterionic Surfactants for Enhanced Oil Recovery

Long-term thermal stability of surfactants under harsh reservoir conditions is one of the main challenges for surfactant injection. Most of the commercially available surfactants thermally degrade or precipitate when exposed to high-temperature and high-salinity conditions. In this work, we designed and synthesized three novel betaine-based polyoxyethylene zwitterionic surfactants containing different head groups (carboxybetaine, sulfobetaine, and hydroxysulfobetaine) and bearing an unsaturated tail. The impact of the surfactant head group on the long-term thermal stability, foam stability, and surfactant–polymer interactions were examined. The thermal stability of the surfactants was assessed by monitoring the structural changes when exposed at high temperature (90 °C) for three months using 1H-NMR, 13C-NMR, and FTIR analysis. All surfactants were found thermally stable regardless of the headgroup and no structural changes were evidenced. The surfactant–polymer interactions were dominant in deionized water. However, in seawater, the surfactant addition had no effect on the rheological properties. Similarly, changing the headgroup of polyoxyethylene zwitterionic surfactants had no major effect on the foamability and foam stability. The findings of the present study reveal that the betaine-based polyoxyethylene zwitterionic surfactant can be a good choice for enhanced oil recovery application and the nature of the headgroup has no major impact on the thermal, rheological, and foaming properties of the surfactant in typical harsh reservoir conditions (high salinity, high temperature).

The Control of Apparent Wettability on the Efficiency of Surfactant Flooding in Tight Carbonate Rocks

In this research, a state-of-the-art experimental core flooding setup is used to assess the efficiency of surfactant flooding as an enhanced oil recovery (EOR) technique in tight carbonate rocks. Specifically, we investigate the role of apparent wettability in governing the effectiveness of surfactant flooding. A series of flooding experiments with well-defined boundary conditions were performed on the low permeability core plug samples of Indiana Limestone (calcite-cemented carbonate grainstones). Experiments were conducted on three samples exhibiting differing apparent wetting characteristics: strongly oil-wet, moderately oil-wet and weakly oil-wet. Initially, the oil-saturated core samples were flooded with brine until the residual oil saturation was achieved, with surfactant flooding performed as a tertiary recovery technique. Interestingly, our experimental results reveal that the efficiency of surfactant flooding increases with the degree of oil-wetness of the tight carbonate rocks. The strongly oil-wet core showed the highest recovery, while the weakly oil-wet core manifested the least additional oil recovery associated with surfactant flooding. Moreover, we provided a pore-scale argument that explains the macroscopic role of surfactant flooding in tight carbonate rocks. We hypothesized that at the pore-scale the presence of thin film plays a critical role in controlling the effectiveness of surfactant flooding in the strongly oil-wet tight carbonate rocks. Overall, we believe that our macroscopic study provides novel insight into the dynamics of surfactant flooding in tight carbonate reservoirs and can aid in optimizing the field development plans for oil recovery.

Role of Counterions and Nature of Spacer on Foaming Properties of Novel Polyoxyethylene Cationic Gemini Surfactants

Application of foam in various upstream operations, such as in enhanced oil recovery, has gained significant attention in recent years. A good foaming agent should generate a stable foam, must be thermally stable (>90 °C, typical reservoir temperature), must have a high tolerance to salinity, and should have low adsorption on the reservoir rock. In view of this, four thermally stable and salt-tolerant polyoxyethylene cationic gemini surfactants were synthesized with different spacers (mono phenyl and biphenyl) and different counterions (Br− and Cl−). Foaming properties were evaluated using initial foam generation, foam volume stability at a given time, bubble count, and average foam bubble radius. The effect of counterions and nature of spacers, with and without the presence of salts, on foaming properties was evaluated. It was found that number of phenyl rings (mono phenyl and biphenyl) had no significant effect on foamability and foam stability in the presence or absence of salts. However, the effect of counterions was prominent in deionized water. In deionized water, foam generated by gemini surfactants with bromide as a counterion was more stable compared to the foam generated using the surfactant containing chloride as the counterion. In saline solution, the type of counterion had no effect on the foamability or foam stability of the foam generated using synthesized cationic gemini surfactants. The foam volume stability decreased by the addition of salts; however, a further increase in salt concentration enhanced the foam volume stability. The synthesized surfactants showed good thermal stability, salt tolerance, and foaming properties and can be an attractive choice for upstream applications.

Enhanced Adsorption of Aqueous Tetracycline Hydrochloride on Renewable Porous Clay-Carbon Adsorbent Derived from Spent Bleaching Earth via Pyrolysis

In this study, spent bleaching earth (SBE) and pyrolyzed SBE (SBE@C) were tested for their capacity to remove tetracycline hydrochloride (TCH) from aqueous solution. The maximum adsorption capacity obtained by the Langmuir model is 0.114 mmol/g for SBE@C and 0.087 mmol/g for SBE. The deleterious effects of coexisting cations were ranked in a decline: Al³⁺ > Mg²⁺ > Na⁺. The results of various characterization methods show that the adsorption mechanisms mainly included π-π interactions, hydrogen bonding, electrostatic interactions, and changes in physical and chemical properties. After 3 repeated cycles of pyrolysis, the adsorption capacity of SBE@C remained at 85.4%, with SBE@C potentially recycled 21 times before complete loss of adsorption capacity. Furthermore, the problem of secondary pollution caused by SBE and residual oil is resolved by the use of SBE@C. All results indicate that SBE@C is a likely candidate for the treatment of TCH wastewater in the coming practical applications.

Static Adsorption of an Ethoxylated Nonionic Surfactant on Carbonate Minerals

The static adsorption of C_12-14E₂₂, which is a highly ethoxylated nonionic surfactant, was studied on different minerals using high-performance liquid chromatography (HPLC) combined with an evaporative light scattering detector (ELSD). Of particular interest is the surfactant adsorption in the presence of CO₂ because it can be used for foam flooding in enhanced oil recovery applications. The effects of the mineral type, impurities, salinity, and temperature were investigated. The adsorption of C_12-14E₂₂ on pure calcite was as low as 0.01 mg/m² but higher on dolomite depending on the silica and clay content in the mineral. The adsorption remained unchanged when the experiments were performed using a brine solution or 0.101 MPa (1 atm) CO₂, which indicates that electrostatic force is not the governing factor that drives the adsorption. The adsorption of C_12-14E₂₂ on silica may be due to hydrogen bonding between the oxygen in the ethoxy groups of the surfactant and the hydroxyl groups on the mineral surface. Additionally, thermal decomposition of the surfactant was severe at 80 °C but can be inhibited by operating in a reducing environment. Under reducing conditions, adsorption of C_12-14E₂₂ increased at higher temperatures.