Search Results (110)

Waterflooding, a key method for secondary hydrocarbon recovery, has been employed since the early 20th century. Over time, the role of water chemistry and ions in recovery has been studied extensively. Low-salinity water (LSW) injection, a common technique since the 1930s, improves oil recovery by altering the wettability of reservoir rocks and reducing residual oil saturation. Recent developments emphasize the integration of LSW with various recovery methods such as CO₂ injections, surfactants, alkali, polymers, and nanoparticles (NPs). This article offers a comprehensive perspective on how LSW injection is combined with these enhanced oil recovery (EOR) techniques, with a focus on improving oil displacement and recovery efficiency. Surfactants enhance the effectiveness of LSW by lowering interfacial tension (IFT) and improving wettability, while ASP flooding helps reduce surfactant loss and promotes in situ soap formation. Polymer injections boost oil recovery by increasing fluid viscosity and improving sweep efficiency. Nevertheless, challenges such as fine migration and unstable flow persist, requiring additional optimization. The combination of LSW with nanoparticles has shown potential in modifying wettability, adjusting viscosity, and stabilizing emulsions through careful concentration management to prevent or reduce formation damage. Finally, building on discussions around the underlying mechanisms involved in improved oil recovery and the challenges associated with each approach, this article highlights their prospects for future research and field implementation. By combining LSW with advanced EOR techniques, the oil industry can improve recovery efficiency while addressing both environmental and operational challenges. Full article

This study establishes a covalently anchored wettability alteration strategy for enhanced oil recovery (EOR) using perfluorinated siloxane (CQ), addressing limitations of conventional modifiers reliant on unstable physical adsorption. Instead, CQ forms irreversible chemical bonds with rock surfaces via Si-O-Si linkages (verified by FT-IR/EDS), imparting durable amphiphobicity with water and oil contact angles of 135° and 116°, respectively. This modification exhibits exceptional stability: increasing salinity from 2536 to 10,659 mg/L reduced angles by only 6° (water) and 4° (oil), while 70 °C aging in aqueous/oleic phases preserved amphiphobicity without reversion—supported by >300 °C thermal decomposition in TGA; confirming chemical bonding durability. Mechanistic analysis identifies dual EOR pathways: amphiphobic surfaces lower rolling angles, surface free energy (SFE), and fluid adhesion to facilitate pore migration, while CQ intrinsically reduces oil-water interfacial tension (IFT). Core displacement experiments showed that injecting 0.05 wt% CQ followed by secondary waterflooding yielded an additional 10–18% increase in oil recovery. This improvement is attributed to enhanced mobilization of residual oil, with greater EOR efficacy observed in smaller pore throats. Field trials at the Huabei Oilfield validated practical applicability: Production rates of test wells C-9 and C-17 increased several-fold, accompanied by reduced water cuts. Integrating fundamental research, laboratory experiments, and field validation, this work systematically demonstrates a wettability-alteration-based EOR method and offers important technical insights for analogous reservoir development. Full article

As conventional waterflooding enters mid-to-late stages, chemical enhanced oil recovery (EOR) technologies such as polymer–surfactant binary flooding have emerged to address declining recovery rates. This study systematically investigates the synergistic effects of polymer–surfactant binary formulations through core-flooding experiments under varying concentrations, injection volumes, and salinity conditions. The optimal formulation, identified as 0.5% surfactant and 0.15% polymer, achieves a maximum incremental oil recovery of 42.19% with an interfacial tension (IFT) reduction to 0.007 mN/m. A 0.5 pore volume (PV) injection volume balances sweep efficiency and economic viability, while sequential slug design with surfactant concentration gradients demonstrates superior displacement efficacy compared with fixed-concentration injection. Salinity sensitivity analysis reveals that high total dissolved solids (TDS) significantly degrade viscosity, whereas low TDS leads to higher viscosity but only marginally enhances the recovery. These findings provide experimental evidence for optimizing polymer–surfactant flooding strategies in field applications, offering insights into balancing viscosity control, interfacial tension reduction, and operational feasibility. Full article

This work examines how multiphase flow behavior during CO₂ and N₂ displacement in a microfluidic chip under capillary-dominated circumstances is affected by interfacial tension (IFT) and the viscosity ratio. In order to simulate real pore-scale displacement operations, microfluidic tests were performed on a 2D rock chip at flow rates of 1, 10, and 100 μL/min (displacement of water by N₂/supercritical CO₂). Moreover, core flooding experiments were performed on various sandstone samples collected from three different geological basins in Australia. Although CO₂ is notably denser and more viscous than N₂, the findings show that its displacement efficiency is more influenced by the IFT values. Low water recovery in CO₂ is the result of non-uniform displacement that results from a high mobility ratio and low IFT; this traps remaining water in smaller pores via snap-off mechanisms. However, due to the blebbing effect, N₂ injection enhances the dissociation of water clots, resulting in a greater swept area and fewer remaining water clusters. The morphological investigation of the residual water indicates various displacement patterns; CO₂ leaves more retained water in irregular shapes, while N₂ enables more uniform displacement. These results confirm earlier studies and suggest that IFT has a crucial role in fluid displacement proficiency in capillary-dominated flows, particularly at low flow rates. This study emphasizes the crucial role of IFT in improving water recovery through optimizing the CO₂ flooding process. Full article

Residual oil saturation in reservoirs is primarily influenced by viscous and capillary forces, with interfacial tension (IFT) being a critical factor in fluid distribution due to capillary pressure. Adjusting IFT is essential for enhancing oil recovery, particularly in waterflooding, which is the most common secondary recovery technique after primary production. The salinity of injected water directly affects the IFT between crude oil and brine, making it a crucial factor in optimizing recovery. However, limited studies have examined IFT using live oil samples under actual reservoir conditions. In this study, a high-pressure, high-temperature (HPHT) drop shape analyzer was used to measure the IFT between live oil and brine under reservoir conditions. Five live oil samples and two sodium chloride (NaCl) brine concentrations (30,000 and 100,000 ppm) were tested at a reservoir temperature of 180 °F. Measurements were conducted above the bubble points of the oils, replicating undersaturated reservoir conditions. The results revealed that the impact of pressure on IFT was more complex than that of salinity. IFT generally decreased with increasing pressure but showed mixed behavior across different samples. Conversely, IFT consistently increased with higher salinity. These findings enhance the understanding of IFT behavior under reservoir conditions, supporting improved reservoir simulations and oil recovery strategies. Full article

Alkyl sulfobetaine shows a strong advantage in the compounding of surfactants due to the defects in the size matching of hydrophilic and hydrophobic groups. The interfacial tensions (IFTs) of alkyl sulfobetaine (ASB) and xylene-substituted alkyl sulfobetaine (XSB) with oil-soluble (Span80) and water-soluble (Tween80) nonionic surfactants on a series of n-alkanes were studied using a spinning drop tensiometer to investigate the mechanism of IFT between nonionic and betaine surfactants. The two betaine surfactants’ IFTs are considerably impacted differently by Span80 and Tween80. The results demonstrate that Span80, through mixed adsorption with ASB and XSB, can create a relatively compacted interfacial film at the n-alkanes–water interface. The equilibrium IFT can be reduced to ultra-low values of 5.7 × 10⁻³ mN/m at ideal concentrations by tuning the fit between the size of the nonionic surfactant and the size of the oil-side vacancies of the betaine surfactant. Nevertheless, Tween80 has minimal effect on the IFT of betaine surfactants, and the betaine surfactant has no vacancies on the aqueous side. The present study provides significant research implications for screening betaine surfactants and their potential application in enhanced oil recovery (EOR) processes. Full article

CO₂-switchable surfactants, applicable for mitigating CO₂ geological storage efficiency challenges, offer promising control over foam stability under reservoir conditions, but their performance under extreme pressure, temperature, and salinity still needs thorough investigation. This study experimentally characterizes the performance of CO₂-switchable surfactants by evaluating their interfacial tension (IFT) reduction, foamability, and foam stability under reservoir-relevant conditions. Six surfactants, including cationic (cetyltrimethylammonium bromide (CTAB) and benzalkonium chloride (BZK)) and nonionic amine-based surfactants (N,N-Dimethyltetradecylamine, N,N-Dimethyldecylamine, and N,N-Dimethylhexylamine), were assessed using synthetic brine mimicking a depleted North Sea oil reservoir. A fractional factorial design was employed to minimize experimental runs while capturing key interactions between surfactant type, temperature, salinity, and divalent ion concentrations. Foam switchability was analyzed by alternating CO₂ and N₂ injections, and interfacial properties were measured to establish correlations between foam generation and IFT. Experimental findings demonstrate that cationic surfactants (BZK and CTAB) exhibit CO₂-switchability and moderate foam stability. Nonionic surfactants show tail length-dependent responsiveness, where D14 demonstrated the highest foamability due to its optimal hydrophilic–hydrophobic balance. IFT measurements revealed that BZK consistently maintained lower IFT values, facilitating stronger foam generation, while CTAB exhibited higher variability. The inverse correlation between IFT and foamability was observed. These insights contribute to the development of tailored surfactants for subsurface CO₂ storage applications, improving foam-based mobility control in CCS projects. Full article

To support computational studies and process optimization that require temperature-dependent thermophysical properties, this study characterized the wettability, surface tension, liquid–solid interfacial tension (IFT), and work of adhesion of Al 7075-T6 alloy from 923–1073 K under argon on porous alumina, tungsten, and nonporous alumina substrates using sessile drop experiments and Young’s and Young–Dupre equations, respectively. Furthermore, the substrates’ room-temperature surface free energy (SFE) characteristics were characterized using the Owens–Wendt–Rabel–Kaelble model. The contact angle results revealed the alloy’s poor wettability on all substrates. The surface tension data ranged from 718.87–942.90 mN·m⁻¹ in decreasing order of tungsten, porous alumina, and nonporous alumina. The SFE results of the porous alumina, nonporous alumina, and tungsten substrates were 44.92, 43.32, and 42.03 mN·m⁻¹, respectively. Also, the calculated liquid–solid IFT values ranged from 539.24–835.51 mN·m⁻¹ in decreasing order of porous alumina, tungsten, and nonporous alumina. Additionally, the calculated work of adhesion values ranged from 123.97–479.44 mN·m⁻¹ in decreasing order of nonporous alumina, tungsten, and porous alumina, respectively. Thus, the wettability, surface tension, and liquid–solid IFT of Al 7075-T6 alloy on the substrates were affected by the substrates’ SFE characteristics, thereby affecting the work of adhesion. Full article

Shale oil is abundant in geological reserves, but its recovery rate is low due to its unique characteristics of ultra-low porosity, ultra-low permeability, and high clay content. This study investigated the effect of mixed-charge surfactants (PSG) on enhanced oil recovery (EOR) in high-temperature shale reservoirs, building on our previous research. The results indicate that PSG not only has outstanding interfacial activity, anti-adsorption, and high-temperature resistance but can also alter the wettability of shale. After aging at 150 °C for one month, a 0.2% PSG solution exhibited minimal influence on the viscosity reduction and oil-washing properties but significantly altered the oil/water interfacial tension (IFT). Compared to field water, the 0.2% PSG solution enhances the static oil-washing efficiency by over 25.85% at 80 °C. Moreover, its imbibition recovery rate stands at 29.03%, in contrast to the mere 9.84% of field water. Because of the small adhesion work factor of the PSG solution system, it has a strong ability to improve shale wettability and reduce oil/water IFT, thereby improving shale oil recovery. This study provides the results of a laboratory experiment evaluation for enhancing shale oil recovery with surfactants. Furthermore, it holds significant potential for application in the single-well surfactant huff-n-puff process within shale reservoirs. Full article

This study investigates the combined effects of impurities in CO₂ stream, geochemistry, water salinity, and wettability alteration on oil recovery and CO₂ storage in carbonate reservoirs and optimizes injection strategy to maximize oil recovery and CO₂ storage ratio. Specifically, it compares the performance of pure CO₂ water-alternating gas (WAG), impure CO₂-WAG, pure CO₂ low-salinity water-alternating gas (LSWAG), and impure CO₂-LSWAG injection methods from perspectives of enhanced oil recovery (EOR) and CO₂ sequestration. CO₂-enhanced oil recovery (CO₂-EOR) is an effective way to extract residual oil. CO₂ injection and WAG methods can improve displacement efficiency and sweep efficiency. However, CO₂-EOR has less impact on the carbonate reservoir because of the complex pore structure and oil-wet surface. Low-salinity water injection (LSWI) and CO₂ injection can affect the complex pore structure by geochemical reaction and wettability by a relative permeability curve shift from oil-wet to water-wet. The results from extensive compositional simulations show that CO₂ injection into carbonate reservoirs increases the recovery factor compared with waterflooding, with pure CO₂-WAG injection yielding higher recovery factor than impure CO₂-WAG injection. Impurities in CO₂ gas decrease the efficiency of CO₂-EOR, reducing oil viscosity less and increasing interfacial tension (IFT) compared to pure CO₂ injection, leading to gas channeling and reduced sweep efficiency. This results in lower oil recovery and lower storage efficiency compared to pure CO₂. CO₂-LSWAG results in the highest oil-recovery factor as surface changes. Geochemical reactions during CO₂ injection also increase CO₂ storage capacity and alter trapping mechanisms. This study demonstrates that the use of impure CO₂-LSWAG injection leads to improved oil recovery and CO₂ storage compared to pure CO₂-WAG injection. It reveals that wettability alteration plays a more significant role for oil recovery and geochemical reaction plays crucial role in CO₂ storage than CO₂ purity. According to optimization, the greater the injection of gas and water, the higher the oil recovery, while the less gas and water injected, the higher the storage ratio, leading to improved storage efficiency. This research provides valuable insights into parameters and injection scenarios affecting enhanced oil recovery and CO₂ storage in carbonate reservoirs. Full article

As an efficient and economical method to enhance oil recovery (EOR), it is very important to explore the applicability of chemical flooding under harsh reservoir conditions, such as high temperature and high salinity. We designed microscopic visualization oil displacement experiments to comprehensively evaluate the oil displacement performance of the zwitterionic surfactant betaine (BSB), a temperature- and salinity-resistant hydrophobically modified polymer (BHR), and surfactant–polymer (SP) binary systems. Based on macroscopic properties and microscopic oil displacement effects, we confirmed that the BSB/BHR binary solution has the potential to synergistically improve oil displacement efficiency and quantified the reduction in residual oil and oil displacement efficiency within the swept range. The experimental results show that after water flooding, a large amount of residual oil remains in the porous media in the form of clusters, porous structures, and columnar formations. After water flooding, only slight emulsification occurred after the injection of BSB solution, and the residual oil could not be activated. The injection of polymer after water flooding can expand the swept range to a certain extent. However, the distribution of residual oil in the swept range is similar to that of water flooding, and the oil washing efficiency is low. The SP binary flooding process can expand sweep coverage and effectively decompose large oil clusters simultaneously. This enhances the oil washing efficiency within the swept area and can significantly improve oil recovery. Finally, we obtained the microscopic oil displacement mechanism of BSB/BHR binary system to synergistically increase the swept volume and effectively activate the residual oil after water flooding. It is the result of the combined action of low interfacial tension (IFT) and suitable bulk viscosity. These findings provide critical insights for optimizing chemical flooding strategies in high-temperature and high-salinity reservoirs, significantly advancing EOR applications in harsh environments. Full article

Hydroxypropyl cellulose (HPC) is a non-digestible water-soluble polysaccharide used in various food, cosmetic, and pharmaceutical applications. In the current study, the aqueous solutions of six HPC grades, with molecular mass ranging from 40 to 870 kDa, were characterized with respect to their precipitation temperatures, interfacial tensions (IFTs), rheological properties and emulsifying and stabilization ability in palm (PO) and sunflower (SFO) oil emulsions. The main conclusions from the obtained results are as follows: (1) Emulsion drop size follows a master curve as a function of HPC concentration for all studied polymers, indicating that polymer molecular mass and solution viscosity have a secondary effect, while the primary effect is the fraction of surface-active molecules, estimated to be around 1–2% for all polymers. (2) Stable emulsions were obtained only with HPC polymers with M_w ≥ 400 kDa at concentrations approximately 3.5 times higher than the critical overlap concentration, c*. At PO concentrations beyond 40 wt. % or when the temperature was 25 °C, these emulsions appeared as highly viscous liquids or non-flowing gels. (3) HPC polymers with M_w < 90 kDa were unable to form stable emulsions, as the surface-active molecules cannot provide steric stabilization even at c ≳ 4–5 c*, resulting in drop creaming and coalescence during storage. Full article

CO₂ is the main solvent used in enhanced oil recovery (EOR). However, its low density and viscosity compared to oil cause a decrease in sweep efficiency. Recently, dimethyl ether (DME), which is more efficient than CO₂, has been introduced into the process. DME improves oil recovery by reducing minimum miscible pressure (MMP), interfacial tension (IFT), and oil viscosity. Since DME is an expensive solvent, price reduction and appropriate injection scenarios are needed for economic feasibility. In this study, a compositional model was developed to inject DME with impure CO₂ streams, where the CO₂ was derived from one of these three purification methods: dehydration, double flash, and distillation. It was assumed that such a mixed solvent was injected into a heterogeneous reservoir where gravity override was maximized. As a result, lower oil recovery is achieved for the higher impurity content of the CO₂ stream, lower DME content, and more heterogeneous reservoir. When a high-purity CO₂ stream is used, the change in oil recovery according to DME content and heterogeneity of the reservoir is increased. When the lowest-purity CO₂ stream is used, the net present value (NPV) is the highest. For a homogeneous reservoir, the NPV is highest for all impure CO₂ streams. This optimization indicates a greater impact on revenue from reduced CO₂ purchase cost than on profit loss due to reduced oil recovery by impurities. Additional benefits can be expected when considering solvent reuse and carbon capture and storage (CCS) credits. Full article

In this paper, the spinning drop method was used to measure the oil–water interfacial dilational modulus of four different types of surfactants with low interfacial tension (IFT), including the anionic surfactant sodium dodecyl sulfate (SDS), the nonionic surfactant Triton X-100 (TX100), the zwitterionic surfactant alkyl sulfobetaine (ASB), and the extended surfactant alkyl polyoxypropyl ether sodium sulfate (S-C₁₃PO₁₃S). Based on the experimental results, we found that the spinning drop method is an effective means of measuring the interfacial dilational modulus of the oil–water interface with an IFT value of lower than 10 mN/m. For common surfactants SDS and TX100, the interfacial dilational modulus decreases rapidly to near zero with an increase in concentration when the IFT is lower than 1 mN/m. On the other hand, ASB has the highest interfacial dilatation modulus of 50 mN/m, which comes from the flatness of its unique hydrophilic group structure. The interfacial dilational modulus of S-C₁₃PO₁₃S showed a moderate plateau value of 30 mN/m with a broader concentration change. This is due to the fact that the main relaxation process dominating the interfacial film properties comes from the long helical polyoxypropyl chain. Through the large-size hydrophilic groups in betaine molecules and the long PO chains in the extended surfactant molecules, an interfacial film with controllable strength can be formed in a low IFT system to obtain a higher interfacial dilational modulus. This is of great significance in improving the emulsification and oil displacement of chemical flooding in reservoir pores. Full article

Enhancing oil recovery efficiency is vital in the energy industry. This study investigates magnesium oxide (MgO) nanoparticles combined with sodium dodecyl sulfate (SDS) surfactants to reduce interfacial tension (IFT) and improve oil recovery. Pendant drop method measurements revealed a 70% IFT reduction, significantly improving nanoparticle dispersion stability due to SDS. Alterations in Zeta Potential and viscosity, indicating enhanced colloidal stability under reservoir conditions, were key findings. These results suggest that the MgO-SDS system offers a promising and sustainable alternative to conventional methods, although challenges such as scaling up and managing nanoparticle–surfactant dynamics remain. The preparation of MgO nanofluids involved magnetic stirring and ultrasonic homogenization to ensure thorough mixing. Characterization techniques included density, viscosity, pH, Zeta Potential, electric conductivity, and electrophoretic mobility assessments for the nanofluid and surfactant–nanofluid systems. Paraffin oil was used as the oil phase, with MgO nanoparticle concentrations ranging from 0.01 to 0.5 wt% and a constant SDS concentration of 0.5 wt%. IFT reduction was significant, from 47.9 to 26.9 mN/m with 0.1 wt% MgO nanofluid. Even 0.01 wt% MgO nanoparticles reduced the IFT to 41.8 mN/m. Combining MgO nanoparticles with SDS achieved up to 70% IFT reduction, enhancing oil mobility. Changes in Zeta Potential (from −2.54 to 3.45 mV) and pH (from 8.4 to 10.8) indicated improved MgO nanoparticle dispersion and stability, further boosting oil displacement efficiency under experimental conditions. The MgO-SDS system shows promise as a cleaner, cost-effective Enhanced Oil Recovery (EOR) method. However, challenges such as nanoparticle stability under diverse conditions, surfactant adsorption management, and scaling up require further research, emphasizing interdisciplinary approaches and rigorous field studies. Full article