Search Results (12)

A low-permeability, high salinity reservoir entered the high-water-cut and high recovery degree stage in the middle and late stages of development, and it is difficult to tap the potential of water flooding. The overall water flooding recovery of the developed low-permeability reservoir is low, and the produced water has high oil content, many granular impurities, and high inorganic salt content. The polymer–surfactant binary system was studied according to the reservoir conditions. The polymer acrylic acid/polyacrylamide/2-acryloylamino-2-methyl-1-propanesulfonic acid was selected by viscosity measurement. The viscosity stability of the polymer and the effect of the flooding system were evaluated, and the salt-tolerant surfactant sulfonated betaine + amides and coco composite system were screened, and the viscosity, interfacial tension, and displacement effect were evaluated. Finally, the polymer–surfactant binary flooding system was formed. The system has good compatibility, the interfacial tension can still be reduced to 10⁻³ mN/m at 40 °C and 23,800 mg/L, and the viscosity of the polymer solution increased by 5.8% upon addition of the surfactant. The composite system can improve the oil displacement efficiency by 21.19%. The results of a parallel core displacement experiment with a 3.91 permeability ratio show that the oil displacement efficiency can be improved by 19.96%. The system has good performance in low-permeability oilfields and can effectively displace crude oil, which is of great significance for the displacement of low-permeability heterogeneous reservoirs. 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

In view of the limited applicability of traditional chemical flooding and binary composite flooding for heavy-oil reservoirs, branched-preformed particle gel (B-PPG) with excellent plugging performance was added to construct the B-PPG/SP (B-PPG/surfactant/polymer) composite system. Through sand pack flooding experiments, it has been proven that the synergistic effect between B-PPG and polymer can expand the swept area and increase the contact between the viscosity reducer and heavy oil, enabling the viscosity reducer to better exert emulsification and viscosity reduction effects. The synergistic effect between B-PPG, polymer and viscosity reducer can further expand the swept area and oil displacement efficiency, ultimately enhancing the heavy-oil recovery by 37.8%. Microscopic visualization flooding experiments proved that cluster remaining oil accounts for the largest proportion in the microscopic remaining oil in heavy oil. By adding B-PPG and polymers, cluster remaining oil can be effectively displaced, thereby significantly enhancing the heavy-oil recovery. And adding viscosity reducer to the composite system can effectively enhance the dispersed residual oil recovery within the swept area. The sand pack flooding experiments with different heavy-oil viscosity proved that the optimal oil viscosity of the B-PPG/SP composite system can reach 657.2 mPa·s, with an incremental oil recovery rate increase of 30.2%. 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

Reservoir heterogeneity significantly affects reservoir flooding efficiency and the formation and distribution of residual oil. As an effective method for enhancing recovery, polymer–surfactant (SP) flooding has a complex mechanism of action in inhomogeneous reservoirs. In this study, the effect of reservoir heterogeneity on the SP drive was investigated by designing core parallel flooding experiments combined with NMR and CT scanning techniques, taking conglomerate reservoirs in a Xinjiang oilfield as the research object. The experimental results show that inter-layer heterogeneity significantly affects water flooding efficiency and SP driving in low-permeability cores—the larger the permeability difference is, the more obvious the effect is—while it has almost no effect on high-permeability cores. The limited recovery enhancement in low-permeability cores is mainly due to the small percentage of contributing pores. When the permeability difference undergoes an extreme increase, the polymer molecular weight is biased towards higher values; when the polymer molecular weight is fixed, the recovery enhancement of low-permeability cores may be comparable to that of high-permeability cores when the permeability difference is extremely small. However, the recovery enhancement of the former is smaller than that of the latter when the permeability difference is extremely large. Due to intra-layer heterogeneity, there is a serious fingering phenomenon in the flooding stage, while in the SP flooding stage, recovery enhancement is most significant in the 5–20 μm pore range. This study provides an important geological basis for the rational development of a chemical flooding programme. 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

The purpose of this study is to clarify the difference in oil production rules of conglomerate reservoirs with different pore structures during surfactant–polymer (SP) binary flooding and to ensure the efficient development of conglomerate reservoirs. In this paper, the full-diameter natural cores from the conglomerate reservoir of the Triassic Kexia Formation in the seventh middle block of the Karamay Oilfield (Xinjiang, China) are selected as the research objects. Two schemes of single constant viscosity (SCV) and echelon viscosity reducing (EVR) are designed to displace oil from three main oil-bearing lithologies, namely fine conglomerate, glutenite, and sandstone. Through comprehensive analysis of parameters, such as oil recovery rate, water content, and injection pressure difference, the influence of lithology on the enhanced oil recovery (EOR) of the EVR scheme is determined, which in turn reveals the differences in the step-wise oil production rules of the three lithologies. The experimental results show that for the three lithological reservoirs, the oil displacement effect of the EVR scheme is better than that of the SCV scheme, and the differences in recovery rates between the two schemes are 9.91% for the fine conglomerate, 6.77% for glutenite, and 6.69% for sandstone. By reducing the molecular weight and viscosity of the SP binary system, the SCV scheme achieves the reconstruction of the pressure field and the redistribution of seepage paths of chemical micelles with different sizes, thus, achieving the step-wise production of crude oil in different scale pore throats and enhancing the overall recovery of the reservoir. The sedimentary environment and diagenesis of the three types of lithologies differ greatly, resulting in diverse microscopic pore structures and differential seepage paths and displace rules of SP binary solutions, ultimately leading to large differences in the enhanced oil recoveries of different lithologies. The fine conglomerate reservoir has the strongest anisotropy, the worst pore throat connectivity, and the lowest water flooding recovery rate. Since the fine conglomerate reservoir has the strongest anisotropy, the worst pore throats connectivity, and the lowest water flooding recovery, the EVR scheme shows a good “water control and oil enhancement” development feature and the best step-wise oil production effect. The oil recovery rate of the two schemes for fine conglomerate shows a difference of 10.14%, followed by 6.36% for glutenite and 5.10% for sandstone. In addition, the EOR of fine conglomerate maintains a high upward trend throughout the chemical flooding, indicating that the swept volume of small pore throats gradually expands and the producing degree of the remaining oil in it gradually increases. Therefore, the fine conglomerate is the most suitable lithology for the SCV scheme among the three lithologies of the conglomerate reservoirs. Full article

Polymers can increase the viscosity of water, reduce the relative permeability of the water phase, and enhance the flowability of the oil phase; surfactants can form molecular films at the oil–water interface boundaries, thereby reducing interfacial tension. Surfactant/polymer (S/P) flooding technology for enhancing oil recovery has become a major way to increase crude oil production. This study used dissipative particle dynamics (DPD) technology to simulate the emulsification process of a four-component composite system consisting of oil, water, sodium dodecylbenzene sulfonate (SDBS), and partially hydrolyzed polyacrylamide (HPAM). By changing the concentration of the S/P system, the effect on emulsification behavior was analyzed. Combined with particle distribution diagrams and interfacial tension parameters, the effect of the emulsification behavior on the performance of the S/P binary system was analyzed. On this basis, the effect of different emulsion performances on the recovery factor was evaluated using micro-experiments. The study found that the S/P system that produced stable emulsification had a lower interfacial tension and relatively good effect on improving the recovery factor. Increasing the concentration of the polymer and surfactant may cause changes in the interfacial film of the emulsion, thereby affecting the ability of the S/P system to reduce interfacial tension and may not improve the oil recovery factor. The research results help to better analyze and screen the S/P system used for oil extraction and improve crude oil recovery. Full article

In order to explore the mechanism responsible for the interactions in the surfactant–polymer composite flooding and broaden the application range of the binary system in heterogeneous oil reservoirs, in this paper, the influences of different surfactants on the viscosity of two polymers with similar molecular weights, partially hydrolyzed polyacrylamide (HPAM) and hydrophobically modified polyacrylamide (HMPAM), were studied at different reservoir environments. In addition, the relationship between the surfactant–polymer synergistic effects and oil displacement efficiency was also investigated. The experimental results show that for HPAM, surfactants mainly act as an electrolyte to reduce its viscosity. For HMPAM, SDBS and TX-100 will form aggregates with the hydrophobic blocks of polymer molecules, reducing the bulk viscosity. However, zwitterionic surfactant aralkyl substituted alkyl sulfobetaine BSB molecules can build “bridges” between different polymer molecules through hydrogen bonding and electrostatic interaction. After forming aggregates with HMPAM molecules, the viscosity will increase. The presence of two polymers all weakened the surfactant oil–water interfacial membrane strength to a certain extent, but had little effect on the interfacial tension. The synergistic effect of the “bridge” between HMPAM and BSB under macroscopic conditions also occurs in the microscopic pores of the core, which has a beneficial effect on improving oil recovery. Full article

Injectability of the polymer solution is a very important factor that determines the effectiveness of polymer flooding for enhanced oil recovery. Here, the medium and low permeability oil reservoir was taken as a research object, and effects of relative molecular weight, concentration and core permeability on the flow and injection performance of a partially hydrolyzed polyacrylamide (HPAM) solution with and without anionic-nonionic surfactant (ANS) were studied by indoor outcrop core physical model experiments. It was found that the influence of HPAM concentration on the flow performance was related to the core permeability. When the core permeability was lower than 59 mD, the resistance factor and residual resistance factor of HPAM increased with increasing the concentration. High molecular weight and low core permeability were not conducive to the injectability of HPAM solutions. The addition of ANS was beneficial in enhancing the injectability of HPAM solution by reducing the critical value of injectability of HPAM solution, which was elucidated by the Hall curve derivative method. In the presence of ANS, the flow pressure gradient and the residual resistance factor of the HPAM solution decreased. It is believed that the injectability of HPAM solution improved by ANS in the medium and low permeability reservoirs can be attributed to decrease in fluid viscosity and competitive adsorption on the surface of porous media. The study provides a new idea and theoretical basis for improving the injectability of an HPAM solution and the application of polymer flooding and a polymer/surfactant binary flooding system in medium and low permeability reservoirs. Full article

Polymer and surfactant (S/P) binary flooding is a widely used chemical flooding technology for enhanced oil recovery (EOR). However, it is mostly used in the five-spot well pattern, and there is little research on the effect of well patterns on its flow law and EOR efficiency in the reservoir. In this paper, the flow intensity of S/P flooding in an inverted seven-spot well unit and its EOR efficiency are investigated. Based on the theoretical derivation and simulation, the flow distribution at different positions in the inverted seven-spot well pattern unit was calculated. The oil displacement efficiency was evaluated by simulating different flow intensities with various flow velocity. The microscopic residual oil of the core at the end of displacement was scanned and recognized. The 2D model was used to simulate the well pattern to clarify the EOR of S/P flooding. The results show that the swept area in the well unit can be divided into the strong swept region (>0.2 MPa); medium swept region (0.1–0.2 MPa); weak swept region (0.03–0.1 MPa); and invalid swept region (<0.03 MPa), according to the pressure gradient distribution. Compared to the five-spot well pattern, the inverted seven-spot well pattern featured a weak swept intensity, but a large swept area and lower water cut rise rate. Increasing the flow intensity can improve oil displacement efficiency, and disperse and displace continuous cluster remaining oil. The 2D model experiments show that the incremental oil recoveries by SP flooding after water flooding in the five-spot well pattern and inverted seven-spot well pattern are 25.73% and 17.05%, respectively. However, the ultimate oil recoveries of two well patterns are similar by considering the previous water flooding. Full article

Strong edge water reservoirs have sufficient natural energy. After long-term natural water flooding development, it is in the stage of ultrahigh water cut. There is an urgent need to change the development mode and improve the development effect. Taking Jidong Oilfield as an example, the mechanism model of strong edge water reservoirs is established by using the method of numerical simulation. Then, the factors and rules affecting the effects of gel-assisted polymer and surfactant binary combination flooding are studied. The screening criteria of gel-assisted polymer and surfactant binary combination flooding in strong edge water reservoirs are obtained. The results show that the existence of edge water is not conducive to binary combination flooding. Smaller water volumetric multiples and larger oil-bearing areas are more suitable for binary combination flooding. Compared with closed reservoirs, binary combination flooding in strong edge water reservoirs is more difficult to establish a displacement pressure gradient. The reservoir with high crude oil viscosity is not suitable for binary combination flooding. Gel-assisted polymer and surfactant binary combination flooding can be adopted for reservoirs with an oil-bearing area greater than 0.2 km², a water volumetric multiple less than 200, and oil viscosity less than 100 mPa·s. The research results are of guiding significance for the reservoir selection of gel-assisted polymer and surfactant binary combination flooding after natural water flooding. Full article