Search Results (48)

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

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

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

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

We focus on optimizing oil displacement in brownfields using alkali polymers (AP) flooding. The goal is to enhance rock–fluid and fluid–fluid interactions to improve oil recovery. The evaluation includes detailed screening of AP mixtures to ensure cost-effectiveness and maximize chemical slug efficiency, using an AP pilot project in Austria as a case study. Key aspects of the study involve assessing fluid properties to select appropriate chemical concentrations. Important parameters include the stability of produced emulsions, interfacial tension (IFT) measurements, and rheological analyses. Rock–fluid interactions were examined through core flooding experiments on both low- and high-permeability core plugs to understand fluid dynamics in heterogeneous reservoirs. A novel part of the research involved simulating the in situ aging of the AP slug, which increases its anionicity over time. Two-phase core flooding with aged chemicals provided insights into the evolution of chemical effectiveness and interactions. We found that an alkali concentration of 7500 ppm was optimal for the AP slug, particularly in its interaction with dead oil with a high total acid number (TAN), leading to emulsions with microscopic instability. Single-phase core flooding showed that the AP slug from Vendor B outperformed that from Vendor A despite mechanical stability issues. However, the additional recovery factor (RF) for polymer A-based slugs was higher in both high- and low-permeability core plugs. The findings suggest that in situ aging of the AP slug could reduce costs and enhance injection performance. Full article

Due to the complex physical properties of low-permeability glutenite reservoirs, the oil recovery rate with conventional development is low. Surfactants are effective additives for enhanced oil recovery (EOR) due to their good ability of wettability alteration and interfacial tension (IFT) reduction, but the reason why imbibition efficiencies vary with different types of surfactants and the mechanism of enhanced imbibition in the glutenite reservoirs is not clear. In this study, the imbibition efficiency and recovery of surfactants including the nonionic, anionic, and cationic surfactants as well as nanofluids were evaluated and compared with produced water (PW) using low-permeability glutenite core samples from the Lower Urho Formation in the Mahu oil field. Experiments of IFT, wettability, emulsification, and imbibition at high-temperature and high-pressure were conducted to reveal the underlying EOR mechanisms of different types of surfactants. The distribution and utilization of oil in different pores during the imbibition process were characterized by a combined method of mercury intrusion and nuclear magnetic resonance (NMR). The main controlling factors of surfactant-enhanced imbibition in glutenite reservoirs were clarified. The results demonstrate that the micropores and mesopores contribute most to imbibition recovery in low-permeability glutenite reservoirs. The anionic surfactant KPS exhibits a good capacity of reducing IFT, wettability alteration, and oil emulsification with the highest oil recovery of 49.02%, 8.49% higher than PW. The nonionic surfactant OP-10 performs well on oil emulsification and wetting modification with imbibition recovery of 48.11%. This study sheds light on the selection of suitable surfactants for enhanced imbibition in low-permeability glutenite reservoirs and improves the understanding of oil production through enhanced imbibition. Full article

Alkali–surfactant–polymer (ASP) flooding is one of the most effective and promising ways to enhance oil recovery (EOR). The synergistic effect between alkali, surfactant, and polymer can respectively promote emulsification performance, reduce interfacial tension, and improve bulk phase viscosity, thus effectively improving flooding efficiency. However, the displacement mechanism of ASP flooding and the contribution of different components to the oil displacement effect still need further discussion. In this study, five groups of chemical slugs were injected into the fracture model after water flooding to characterize the displacement effect of weak alkali, surfactant, polymer, and their binary/ternary combinations on residual oil. Additionally, the dominant mechanism of the ASP flooding system to improve the recovery was studied. The results showed that EOR can be improved through interfacial reaction, low oil/water interfacial tension (IFT), and increased viscosity. In particular, the synergistic effect of ASP includes sweep and oil washing. As for sweep, the swept volume is expanded by the interfacial reaction between the alkali and the acidic components in Daqing crude oil, and the polymer increases the viscosity of the system. As for oil washing, the surfactant generated by the alkali cooperates with surfactants to reduce the IFT to an ultra-low level, which promotes the formation and migration of oil-in-water emulsions and increases the efficiency of oil washing. Overall, ASP can not only activate discontinuous oil ganglia in the pores within the water flooding range, but also emulsify, decompose, and migrate the continuous residual oil in the expanded range outside the water flooding. The EOR of ASP is 38.0% higher than that of water flooding. Therefore, the ASP system is a new ternary composite flooding technology with low cost, technical feasibility, and broad application prospects. Full article

For over four decades, carbon dioxide (CO₂) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO₂ are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO₂ would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs. Full article

A novel micro-dispersed-gel (MDG)-strengthened-alkali-compound flooding system was proposed for enhanced oil recovery in high-water-cut mature oilfields. Micro-dispersed gel has different adaptability and application schemes with sodium carbonate and sodium hydroxide. The MDG-strengthened-alkali flooding system can reduce the interfacial tension to an ultra-low interfacial-tension level of 10⁻² mN/m, which can reverse the wettability of rock surface. After 30 days aging, the MDG-strengthened-Na₂CO₃ flooding system has good viscosity retention of 74.5%, with an emulsion stability of 79.13%. The enhanced-oil-recovery ability of the MDG-strengthened-Na₂CO₃ (MDGSC) flooding system is 43.91%, which is slightly weaker than the 47.78% of the MDG-strengthened-NaOH (MDGSH) flooding system. The crude-oil-production mechanism of the two systems is different, but they all show excellent performance in enhanced oil recovery. The MDGSC flooding system mainly regulates and seals micro-fractures, forcing subsequent injected water to enter the low-permeability area, and it has the ability to wash the remaining oil in micro-fractures. The MDGSH flooding system mainly removes the remaining oil on the rock wall surface in the micro-fractures by efficient washing, and the MDG particles can also form weak plugging of the micro-fractures. The MDG-strengthened-alkali flooding system can be used as an alternative to enhance oil recovery in high-water-cut and highly heterogeneous mature oilfields. Full article

Polymer flooding has achieved considerable success in medium–high permeability reservoirs. However, when it comes to low-permeability reservoirs, polymer flooding suffers from poor injectivity due to the large molecular size of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM). Herein, an amphiphilic polymer (LMWAP) with a low MW (3.9 × 10⁶ g/mol) was synthesized by introducing an amphiphilic monomer (Allyl-OP-10) and a chain transfer agent into the polymerization reaction. Despite the low MW, LMWAP exhibited better thickening capability in brine than its counterparts HPAM-1800 (MW = 1.8 × 10⁷ g/mol) and HPAM-800 (MW = 8 × 10⁶ g/mol) due to the intermolecular hydrophobic association. LMWAP also exhibited more significant shear-thinning behavior and stronger elasticity than the two counterparts. Furthermore, LMWAP possesses favorable oil–water interfacial activity due to its amphiphilicity. The oil–water interfacial tension (IFT) could be reduced to 0.88 mN/m and oil-in-water (O/W) emulsions could be formed under the effect of LMWAP. In addition, the reversible hydrophobic association endows the molecular chains of LMWAP with dynamic association–disassociation transition ability. Therefore, despite the similar hydrodynamic sizes in brine, LMWAP exhibited favorable injectivity under low-permeability conditions, while the counterpart HPAM-1800 led to fatal plugging. Furthermore, LMWAP could enhance oil recovery up to 21.5%, while the counterpart HPAM-800 could only enhance oil recovery by up to 11.5%, which could be attributed to the favorable interfacial activity of LMWAP. Full article

Low-salinity water flooding/smart water flooding (LSWF/SWF) are used for enhanced oil recovery (EOR) because of the improved extraction efficiency. These methods are more environmentally friendly and in many scenarios more economical for oil recovery. They are proven to increase recovery factors (RFs) by between 6 and 20%, making LSWF/SWF technologies that should be further evaluated to replace conventional water flooding or other EOR methods. Fluid/fluid interaction improvements include interfacial tension (IFT) reduction, viscoelastic behavior (elastic properties modification), and microemulsion generation, which could complement the main mechanisms, such as wettability alteration. In this research, we evaluate the importance of fluid/fluid mechanisms during LSWF/SWF operations. Our study showed that a substantial decrease in IFT occurs when the oil asphaltene content is in the range of 0% to 3 wt.%. An IFT reduction was observed at low salinity (0–10,000 ppm) and a specific oil composition condition. Optimal IFT occurs at higher divalent ion concentrations when oil has low asphaltene content. For the oil with high asphaltene content, the sulfates concentration controls the IFT alteration. At high asphaltene concentrations, the formation of micro-dispersion is not effective to recover oil, and only a 5% recovery factor improvement was observed. The presence of asphaltene at the oil/low-salinity brine interface increases the energy required to disrupt it, inducing significant changes in the elastic moduli. In cases of low asphaltene content, the storage modulus demonstrates optimal performance at higher divalent concentrations. Conversely, at high asphaltene concentrations, the dominant factors to control the interface are paraffin content and temperature. Full article

Low-tension gas (LTG) flooding has been proven in lab-scale experiments to be a viable tertiary enhanced oil recovery (EOR) technique in low-permeability (~10 mD) oil-wet carbonates. Work carried out previously almost exclusively focused on water-wet cores. The application of LTG in oil-wet carbonates is investigated in this study along with the impact of a hydrocarbon (HC) mixture as the injection gas on oil–water microemulsion phase behavior. The optimum injection gas fraction (ratio of gas injection rate to total injection rate of gas and water) for the hydrocarbon gas mixture in oil-wet carbonates regarding the oil recovery rate was determined to be 60% as it resulted in around 50% residual oil in place (ROIP) recovery. It was shown that proper mobility control can be achieved under these conditions even in the absence of strong foam. The effect of HC gas dissolution in oil was clearly shown by replacing the injection HC gas with nitrogen under the same conditions. Furthermore, the importance of ultra-low interfacial tension (IFT) produced by the injection gas and surfactant slug is proven by comparing injection at sub-optimum salinity to injection at optimum salinity. Full article