Displacement Efficiency Research Articles

Research and Application of Oxygen-Reduced-Air-Assisted Gravity Drainage for Enhanced Oil Recovery

This paper summarizes the research progress and applications of oxygen-reduced-air-assisted gravity drainage (OAGD) in enhanced oil recovery (EOR). The fundamental principles and key technologies of OAGD are introduced, along with a review of domestic and international field trials. Factors influencing displacement performance, including low-temperature oxidation reactions, injection rates, and reservoir dip angles, are discussed in detail. The findings reveal that low-temperature oxidation significantly improves the recovery efficiency through the dynamic balance of light hydrocarbon volatilization and fuel deposition, coupled with the synergistic optimization of the reservoir temperature, pressure, and oxygen concentration. Proper control of the injection rate stabilizes the oil–gas interface, expands the swept volume, and delays gas channeling. High-dip reservoirs, benefiting from enhanced gravity segregation, demonstrate superior displacement efficiency. Finally, the paper highlights future directions, including the optimization of injection parameters, deepening studies on reservoir chemical reaction mechanisms, and integrating intelligent gas injection technologies to enhance the effectiveness and economic viability of OAGD in complex reservoirs.

Enhancing Oil Recovery in Vertical Heterogeneous Sandstone Reservoirs Using Low-Frequency Pulsating Water Injection

Enhanced oil recovery (EOR) techniques, such as water flooding, often face significant challenges in heterogeneous reservoirs, mainly due to permeability variations that hinder effective oil displacement. This study investigated the impact of pulsating water flooding on oil recovery in reservoirs with vertical heterogeneity, focusing on interlayer and inlayer permeability variations. Laboratory experiments were conducted using cylindrical sand pack models with varying permeability to compare steady-state and pulsating water injection methods. The results demonstrated that pulsating water flooding significantly improved vertical sweep efficiency (VSE) and overall oil recovery, particularly in low-permeability zones. Pulsations helped mobilize trapped oil and redistributed injected water more evenly, mitigating the adverse effects of early water breakthrough and enhancing sweep efficiency. For interlayer heterogeneity, pulsating water injection increased total recovery by 23.2%, 8.9%, and 6.6% for core groups with permeability contrasts of 307.9 × 10⁻3 μm2, 193.9 × 10⁻3 μm2, and 73.25 × 10⁻3 μm2, respectively. For inlayer heterogeneity, recovery factors improved by 13.9%, 10.6%, and 3.1%, respectively. Core groups with higher permeability contrasts (i.e., larger differences between high and low permeability) experienced lower recovery under steady-state conditions, while pulsating injection mitigated these effects, resulting in higher recovery in more heterogeneous reservoirs than steady-state flooding. These findings suggest that pulsating water flooding is an effective and cost-efficient technique for enhancing oil recovery in heterogeneous reservoirs. It improves short-term and long-term recovery by increasing displacement efficiency, particularly in low-permeability regions, and effectively mitigates the challenges of permeability variations. As such, pulsating water flooding offers a significant improvement over steady-state flooding, providing valuable insights for EOR practices in complex reservoirs.

Experimental Study on the Application of Polymer Agents in Offshore Oil Fields: Optimization Design for Enhanced Oil Recovery.

The Bohai oilfield is characterized by severe heterogeneity and high average permeability, leading to a low water flooding recovery efficiency. Polymer flooding only works for a certain heterogeneous reservoir. Therefore, supplementary technologies for further enlarging the swept volume are still necessary. Based on the concept of discontinuous chemical flooding with multi slugs, three chemical systems, which were polymer gel (PG), hydrophobically associating polymer (polymer A), and conventional polymer (polymer B), were selected as the profile control and displacing agents. The optimization design of the discontinuous chemical flooding was investigated by core flooding experiments and displacement equilibrium degree calculation. The gel, polymer A, and polymer B were classified into three levels based on their profile control performance. The degree of displacement equilibrium was defined by considering the sweep conditions and oil displacement efficiency of each layer. The effectiveness of displacement equilibrium degree was validated through a three-core parallel displacement experiment. Additionally, the parallel core displacement experiment optimized the slug size, combination method, and shift timing of chemicals. Finally, a five-core parallel displacement experiment verified the enhanced oil recovery (EOR) performance of discontinuous chemical flooding. The results show that the displacement equilibrium curve exhibited a stepwise change. The efficiency of discontinuous chemical flooding became more significant with the number of layers increasing and heterogeneity intensifying. Under the combination of permeability of 5000/2000/500 mD, the optimal chemical dosage for the chemical discontinuous flooding was a 0.7 pore volume (PV). The optimal combination pattern was the alternation injection in the form of "medium-strong-weak-strong-weak", achieving a displacement equilibrium degree of 82.3%. The optimal shift timing of chemicals occurred at a water cut of 70%, yielding a displacement equilibrium degree of 87.7%. The five-core parallel displacement experiment demonstrated that discontinuous chemical flooding could get a higher incremental oil recovery of 24.5% compared to continuous chemical flooding, which presented a significantly enhanced oil recovery potential.

Differences in CH4 Displacement Efficiency by CO2/N2 Injection in Anthracite under Isobaric and High Pressures: Molecular Dynamics Insights

Differences in CH₄ Displacement Efficiency by CO₂/N₂ Injection in Anthracite under Isobaric and High Pressures: Molecular Dynamics Insights

Numerical simulation and parametric optimization of harmonic pulse water flooding technology

Pulse water injection technology is an emerging enhanced oil recovery method that improves oil-water interface and flow characteristics by periodically varying the injection rate. This study, using the TOUGH2 simulator, examines the impact of different pulse injection waveforms (sine, triangle, and square) on the recovery factor in medium to low-permeability carbonate reservoirs. It highlights that pulse water injection outperforms constant rate injection, with the triangle waveform yielding the best recovery rates. Through controlled simulations, findings indicate that increasing pulse injection time and amplitude enhances recovery and water flow. However, frequency variations in ultra-low frequency pulses have minimal effects on recovery. Additionally, the efficiency of pulse water injection is inversely related to reservoir porosity and permeability, while higher oil viscosity significantly boosts recovery efficiency. Conversely, increasing water temperature reduces dynamic viscosity, affecting the oil-water interface lag and decreasing overall displacement efficiency. The study also notes significant differences between heterogeneous and homogeneous reservoir models, emphasizing the need for future large-scale numerical modeling to consider reservoir heterogeneity. These findings provide valuable insights for optimizing pulse water injection in medium to low-permeability reservoirs, supporting practical oil field development strategies.

N2 influences on CH4 accumulation and displacement in shale by molecular dynamics

N2 is generally employed as a displacement agent to enhance gas recovery in shale gas-bearing reservoirs. However, the primary displacement mechanism in the subsurface still needs to be clarified due to the characteristics of shale reservoirs with low porosity and abundant nanopores. This study employs the Molecular Dynamics (MD) simulation method to investigate the effects of N2 on the CH4 accumulation and displacement processes by adopting practical conditions in the subsurface environment. In equilibrium MD simulation processes, including the N2 from outside and inner kerogen matrix, keeping the gas ratio of 1:3 for CH4 and N2, the displacement is 52.4% and 65.3%, respectively, which suggests that CH4 cannot be entirely displaced by surrounding N2 particles, owing to the strong interaction between CH4 and the kerogen matrix. For the straightforward displacement process by N2, the displacement efficiency is enhanced by 71.7% at the 1:1 gas ratio. Another case of N2, in which generation is accompanied by displacement processes, at the ratio 1:2 for N2:CH4, shows a 47.1% displacement efficiency. This work evidences that the straightforward displacement process is more efficient on CH4 displacement, which enhances CH4 production at a pronounced scale and sheds light on the N2 displacement process in industrial shale gas reservoir production.

Study on Improving Recovery of Highly Heterogeneous Reservoirs by Unsteady Water Injection Technology

Unstable water injection can effectively improve the recovery ratio of reservoirs with strong heterogeneity. However, the oil displacement mechanism and the determination method of unstable water injection parameters still need to be clarified, especially for complex fracture reservoirs, which greatly restrict the popularization and development of unstable water injection technology. This paper studies unstable water injection technology in highly heterogeneous reservoirs from the core and reservoir scales, utilizing many displacement experiments and numerical simulations. The differences in oil displacement efficiency, remaining oil distribution, pressure field, and streamlines between continuous water injection and unstable water injection are compared and evaluated. Five flow stages of unstable injection and production are precisely divided, and the microscopic and macroscopic displacement mechanism is clarified. A numerical model of two injection wells and one production is established to determine the best time to implement unstable water injection technology. Based on the principle of pressure superposition, the expression of pressure field distribution between injection and production well in each period of unstable water injection is analytically solved. This formula has provided a new development parameter optimization method aiming at the maximum pressure fluctuation range and optimized the development technology parameters in the water injection process. The results show that precise control injection and production parameters can expand water swept volume, effectively improve the degree of reserve utilization, and improve the recovery of complex reservoirs by 3–7%, which provides a reliable basis for the practical implementation of unstable water injection technology.

Experimental Investigation of Factors Affecting Oil Recovery and Displacement Efficiency of CO2 Injection in Carbonate Reservoirs

Summary Miscible gas injection is the most widely applied enhanced oil recovery (EOR) method in light oil carbonate reservoirs as a tertiary and secondary method. Miscible gas has high displacement efficiency and usually results in a low residual oil saturation (Sorm) in the parts of the reservoirs that are in contact with the gas. Accurate determination of Sorm and understanding the parameters that affect displacement efficiency are crucial for successful miscible gas EOR projects. In this paper, we present a comprehensive experimental program designed to investigate the effect of a number of parameters on oil recovery, displacement efficiency, and Sorm of miscible and near-miscible carbon dioxide (CO2) injection. The parameters investigated in this study are the experimental pressure, pore volume (PV) injected, injection rate, rock type, and initial water saturation (Swi). The coreflood experiments were performed using live crude oil at pressures starting below the minimum miscibility pressure (MMP) to pressure well above the MMP, using reservoir core samples of up to 1 ft long and 2 in. diameter. All CO2 injection experiments were performed using vertically oriented cores, with gas injection from the top to ensure stable displacement. The experimental results show that (1) Oil recovery decreases as pressure decreases with Sorm increasing by more than 20 saturation units as the pressure decreases from 4,250 psi to 2,700 psi; (2) CO2 breakthrough was much earlier at lower pressure, which leads to more CO2 recycling and potentially lower CO2 sequestration volume; (3) the recovery factor (RF) is strongly affected by the PV injected, and this effect is much more significant for the experiments performed at lower pressure; (4) the injection rate has an insignificant impact on oil recovery and Sorm for miscible or near-miscible CO2, due to the low interfacial tension (IFT) between oil and CO2; (5) rock heterogeneity has a strong effect on oil recovery and CO2 breakthrough and hence on CO2 recycling and economy of the projects; and (6) the presence of mobile water at the beginning of CO2 injection resulted in lower displacement efficiency and increased Sorm. However, this water blocking effect should be determined experimentally for a given reservoir rock/fluid system. The results of this study cannot be generalized for other reservoirs. The results of this study have important implications for the design and performance predictions of CO2 injection in the reservoirs under study. Starting CO2 injection at reservoir pressure, which, in some cases, is more than 1,500 psi above MMP, is recommended due to its superior displacement efficiency and less CO2 recycling due to later breakthrough. However, a higher pressure may negatively impact the required CO2 volume, the compression cost, and project economics.

Micro- and macroscopic experiments on self-adaptive mobility control and displacement efficiency of carbon-based composite nanofluid for enhanced oil recovery

Micro- and macroscopic experiments on self-adaptive mobility control and displacement efficiency of carbon-based composite nanofluid for enhanced oil recovery

Optimizing nanoparticle selection for enhanced oil recovery in carbonate rock using hybrid low salinity water flooding

This study explores the potential of SiO2 and Al2O3 nanoparticles (NPs) to enhance oil recovery in carbonate reservoirs through a novel hybrid low salinity water flooding (LSWF) approach. By evaluating four injection fluids—deionized (DI) water/SiO2, DI/Al2O3, low salinity water (LSW)/SiO2, and LSW/Al2O3—this research systematically examines their effects on rock surface wettability and interfacial tension. The findings reveal a key finding: the LSW/NP flooding process effectively balances NP-induced plugging and rock dissolution, thereby maintaining the pore structure integrity of carbonate rocks. SiO2 NPs demonstrated a unique ability to shift rock wettability from oil-wet to intermediate-wet conditions, while Al2O3 NPs exhibited superior interfacial activity, significantly reducing interfacial tension. Notably, hydrophobic Al2O3 NPs achieved the most substantial reduction in capillary pressure, facilitating an earlier breakthrough and enhanced oil displacement efficiency. Among all injection fluids, LSW/Al2O3 emerged as the optimal choice, delivering faster and more efficient oil recovery compared to DI/NP systems. This study is pivotal in demonstrating the combined effects of LSW and tailored NP properties, offering a effective approach for enhanced oil recovery (EOR) in carbonate reservoirs. The findings underscore the importance of selecting appropriate NPs to optimize hybrid LSWF processes and provide practical guidance for the design of next-generation EOR technologies.

Methodology for optimizing high-viscosity oil production using a nature-inspired algorithm

To maintain reservoir pressure above the saturation pressure of oil with gas and effectively displace oil from the reservoir, flooding remains an established operating practice in the fields of the Russian Federation. In recent years, theoretical and practical research into this method of operation has been actively developing. Thus, the low efficiency of oil displacement by flooding has been established in conditions of low oil mobility compared to water, which is especially evident in heterogeneous reservoirs. The highest reduction in the efficiency of the process of replacing oil with water is observed during the development of highly viscous oil fields. For these difficult conditions, polymer flooding technology is especially promising, because the polymer, thickening the water, increases its viscosity, increasing the displacing ability of water. However, for the practical application of polymer flooding, it is necessary to optimize the process by justifying technological parameters (polymer concentration, injection rate) to achieve maximum efficiency. For this purpose, the paper presents a methodological approach based on the use of a nature-inspired optimization algorithm ‒ a flock of migratory birds, used to solve a number of practical nonlinear optimization problems. Keywords: flooding; polymer compositions; mathematical modeling; optimization objective function; nature-inspired algorithms; migrating bird algorithm; net present value.

Molecular Dynamics Simulation of the Effect of Shale Wettability on CO2 Enhanced Oil Recovery.

The wettability of shale is an important factor affecting oil and gas extraction, and conventional experimental methods are difficult to study at the nanoscale. Moreover, most existing studies are qualitatively based on the wettability of rock surfaces with little consideration for their impact on the CO2-EOR. This study employs molecular dynamics simulation methods to conduct an in-depth analysis of the role of rock surface wettability in the CO2-enhanced oil recovery (EOR) process. The research findings indicate that as the surface hydroxyl content increases, the adsorption affinity for CO2 is enhanced, with the selectivity increasing exponentially from 0.74 in the strongly oleophilic wetting (SOW) pore to 3.62 in the strong hydrophilic wetting (SHW) pore. Additionally, variations in wettability result in different types of CO2 displacement. As oil wettability decreases, the contact interface between CO2 and oil changes from a convex to a concave shape. Moreover, different types of wettability result in different dynamic contact angle changes over time, which significantly impacts various displacement stages. A comprehensive comparison shows that pores exhibiting oil-wet characteristics reduce the efficiency of the CO2-EOR. Finally, the investigation explored the influence of pore structure on oil displacement efficiency. In double pores, when the larger pores exhibit hydrophobic characteristics, they further accelerate the displacement speed of the smaller pores. In connected pores, the presence of notch speeds up the displacement effect within the smaller pores, reducing the impact of wettability on displacement efficiency. This study deeply analyzes the role of shale surface wettability in the CO2-EOR process, revealing the impact of wettability on the CO2 adsorption affinity, fluid displacement, oil displacement efficiency, and flow characteristics of shale oil, providing an important theoretical basis for optimizing the CO2-EOR process by adjusting wettability.

Investigating the Impact of Polymers on Clay Flocculation and Residual Oil Behaviour Using a 2.5D Model.

In the process of oilfield development, the surfactant-polymer (SP) composite system has shown significant effects in enhancing oil recovery (EOR) due to its excellent interfacial activity and viscoelastic properties. However, with the continuous increase in the volume of composite flooding injection, a decline in injection-production capacity (I/P capacity) has been observed. Through the observation of frozen core slices, it was found that during the secondary composite flooding (SCF) process, a large amount of residual oil in the form of intergranular adsorption remained in the core pores. This phenomenon suggests that the displacement efficiency of the composite flooding may be affected. Research has shown that polymers undergo flocculation reactions with clay minerals (such as kaolinite, Kln) in the reservoir, leading to the formation of high-viscosity mixtures of migrating particles and crude oil (CO). These high-viscosity mixtures accumulate in local pores, making it difficult to further displace them, which causes oil trapping and negatively affects the overall displacement efficiency of secondary composite flooding (SCF). To explore this mechanism, this study used a microscopic visualization displacement model (MVDM) and microscopy techniques to observe the migration of particles during secondary composite flooding. By using kaolinite water suspension (Kln-WS) to simulate migrating particles in the reservoir, the displacement effects of the composite flooding system on the kaolinite water suspension, crude oil, and their mixtures were observed. Experimental results showed that the polymer, acting as a flocculant, promoted the flocculation of kaolinite during the displacement process, thereby increasing the viscosity of crude oil and affecting the displacement efficiency of secondary composite flooding.

Enhancing Oil Recovery in Low Permeability Reservoirs through CO2 Miscible Flooding: Mechanisms and Dynamics.

Understanding the dynamic characterization of the CO2 miscible flooding process in low permeability reservoirs and its mechanism for oil recovery enhancement is crucial for controlling CO2 miscible flooding sweep efficiency and further enhancing oil recovery. This study was conducted in a low permeability reservoir in Jilin, China, using both online nuclear magnetic resonance CO2 miscible flooding and long-core CO2 miscible flooding experiments. A refined dynamic characterization of the CO2 miscible flooding process from the macroscopic core scale to the microscopic pore scale was achieved through multiple spatial online nuclear magnetic resonance testing methods. Analysis of dynamic characteristics of physical parameters was based on long-core displacement experiments and gas chromatography. This study summarizes the influence mechanism of CO2 miscible flooding on enhanced oil recovery in low permeability reservoirs and demonstrates the feasibility of CO2 miscible flooding. The results indicated that (1) CO2 miscible flooding enables simultaneous oil recovery from micro-, meso-, and macropores, significantly improving displacement efficiency. (2) The recovery process unfolds in two stages: the initial CO2 miscible flooding stage before gas breakthrough and the subsequent CO2 miscible transport stage after gas breakthrough. (3) Both stages are instrumental in expanding the macroscopic swept range of CO2, thereby enhancing oil recovery. (4) The miscibility of CO2 with crude oil can affect the oil's composition. (5) The combined effect of miscible flooding and transport underpins the high displacement efficiency of CO2 miscible flooding. Emphasizing these critical aspects could enhance oil recovery from CO2 miscible flooding in field production.

Mechanisms of microbubble vibration in water-gas dispersion system enhancing microscopic oil displacement efficiency

Mechanisms of microbubble vibration in water-gas dispersion system enhancing microscopic oil displacement efficiency

Damage mechanism analysis of polymer gel to petroleum reservoirs and development of new protective methods based on NMR technique

Polymer gels are widely used in water control and enhanced oil recovery in oil fields. However, the damage mechanism of polymer gels to layers with remaining oil and not requiring plugging and corresponding protective measures are unclear. In this paper, we investigated polymer gels' damage and protection performance through static gel-breaking experiments and dynamic plugging and oil recovery evaluations on rock cores. Moreover, nuclear magnetic resonance (NMR) technology was combined to analyze the damage performance of polymer gels on cores from the pore scale. In addition, a protective technique based on gel breakers for layers with remaining oil and not requiring plugging was proposed. Results showed that when polymer gels were injected into heterogeneous cores, they plugged high-permeability layers while also penetrating low-permeability layers. When the damage to the low-permeability layers was not alleviated, the conformance and oil displacement efficiency were significantly reduced. When the concentration of ammonium persulfate was 2%–5%, the gel-breaking time was shortest and the residue was very minimal. Ammonium persulfate could be used as a gel breaker and reservoir protective material. Furthermore, after injecting ammonium persulfate into heterogeneous reservoir cores, the gel damage on the face of low-permeability layers was relieved. Consequently, the improvement in sweep efficiency was achieved, showing the re-activation of the remaining oil in medium-low permeability layers. Therefore, the low-permeability layer protection process and core experiment study based on gel-breaking agents proposed in this study were suggested to provide a new technique for the field application of conformance modification agents, aiming to achieve higher recovery degrees.

Analyzing Binding Specificity in a Microparticle-Based DNA Displacement Assay Using Multiharmonic QCM-D.

Employing particles as a label is a common approach for signal amplification in various surface-based biosensors. However, the size dependency of adhesive forces can increase the likelihood of nonspecific interactions between the particles and surface. Hence, using microscale particles in surface-based sensors requires both developing surface chemistries with enhanced antifouling properties and precise methods for evaluating these properties. Here we employ a quartz crystal microbalance with dissipation monitoring (QCM-D) to investigate the binding specificity of microparticles anchored multivalently to DNA-functionalized surfaces. We design a competitive particle displacement assay by implementing toehold-mediated strand displacement as an actuator in the microparticle-substrate interface, in which specifically anchored particles dissociate from the surface upon DNA displacement. We evaluate the efficiency of particle displacement in various modified surfaces by measuring the dissipation change (ΔD) following the addition of invader single-strand DNA. We further show that, prior to the particle displacement step, the specificity of particle binding can be inferred from comparing QCM-D harmonics in the particle binding step. Our results suggest that the frequency of zero crossing in the coupled-resonator model, fZC, can be used to characterize the specificity of particle binding. In combination, fZC in the particle binding step and ΔD in the particle displacement step can be considered synergic measures for evaluating the specificity of particle binding on DNA-coated surfaces.

Study on the Microscopic Distribution Pattern of Residual Oil and Exploitation Methods Based on a Digital Pore Network Model.

With the persistent rise in global energy demand, the efficient extraction of petroleum resources has become an urgent and critical issue. Polymer flooding technology, widely employed for enhancing crude oil recovery, still lacks an in-depth understanding of the distribution of residual oil within the microscopic pore structure and the associated displacement mechanisms. To address this, a digital pore network model was established based on mercury intrusion experimental data, and pore structure visualization was achieved through 3Dmax software, simulating the oil displacement process under various polymer concentrations, molecular weights, and interfacial tension conditions. The findings reveal that moderately increasing the polymer concentration (from 1000 [mg/L] to 2000 [mg/L]) improves the recovery factor during polymer flooding by approximately 1.45%, effectively emulsifying larger masses of residual oil and reducing the proportion of throats with high oil saturation. However, when the concentration exceeds 2500 [mg/L], the dispersion of residual oil is hindered, and the enhancement in displacement efficiency becomes marginal. Increasing the molecular weight from 12 million to 16 million and subsequently to 24 million elevates the recovery factor by approximately 1.07% and 1.37%, respectively, reducing clustered residual oil while increasing columnar residual oil; high molecular weight polymers exhibit a more significant effect on channels with high oil saturation. Lowering the interfacial tension (from 30 [mN/m] to 0.005 [mN/m]) markedly enhances the binary flooding recovery factor, with the overall recovery reaching 71.72%, effectively reducing the residual oil within pores of high oil saturation. The study concludes that adjusting polymer concentration, molecular weight, and interfacial tension can optimize the microscopic distribution of residual oil, thereby enhancing oil displacement efficiency and providing a scientific foundation for further improving oilfield recovery and achieving efficient reservoir development.

Synthesis and application of an amphiphilic polymer bearing benzimidazole and long alkyl benzene sulfonamide groups for enhancing heavy oil recovery

Using acrylamide (AM), sulfobetaine methacrylate (SBMA), glycidyl methacrylate (GMA), and N,N-diallyl-4-dodecyl benzene sulfonamide (DBDAP) with long carbon chain and benzene ring as monomers, polymer P(ASGD) was prepared by free-radical micellar copolymerization. Benzimidazole is a heterocyclic aromatic organic compound and it shows similar polarity and structure with asphaltene, by undergoing a ring open reaction between epoxy groups on polymer P(ASGD) and amino groups on 2-aminobenzimidazole(AMZ), a novel amphiphilic polymer named HOVR was obtained. The chemical structure and thermodynamic stability of HOVR were evaluated using FT-IR, 1H NMR and TGA analyses, respectively. Meanwhile, polymer P(ASD) without benzimidazole group, P(ASG) without benzene sulfonamide group, and P(AS) without these two functional groups were synthesized and compared with the properties of HOVR. The potential of polymers for enhancing heavy oil recovery including rheological properties, interfacial activity, wettability alternation, and viscosity reduction ability of heavy oil were studied. In the presence of HOVR, hydrogen bonding and π-π stacking interactions can be formed between HOVR and asphaltene molecules, then the overlapping and stacking structure of asphaltene aggregates collapsed, coupled with the reduction of IFT, the heavy oil was emulsified to form O/W emulsion with small size and uniform distribution, so the viscosity reduction rate (VRR) achieved 95.1 % for 2000 mg/L HOVR at 60 °C and oil/water ratio of 5:5, while the VRR of P(AS), P(ASD) and P(ASG) is 63.5 %, 84.2 % and 83.4 %. Meanwhile, the synergistic effects of benzimidazole and long alkyl benzene sulfonamide enabled HOVR to possess superior ability in increasing aqueous phase viscosity and shifting oil-wetting solid surface towards water-wetting compared with other three polymers. The reversal of wettability can convert capillary resistance into driving force during the displacement process. The oil displacement experiments in core-flooding tests indicated that the cumulative recovery rate was increased by 19.2 %, 11.2 %, 10.2 % and 7.7 % for polymer HOVR, P(ASG), P(ASD) and P(AS) with concentration of 2000 mg/L. The superior efficiency of heavy oil displacement by HOVR is attributed to the enhancements in macroscopic sweep volume and microscopic displacement efficiency, as confirmed by the glass-etched micro-model experiment, and NMR test conducted during the oil displacement process.

A Microscopic Experimental Study on the Dominant Flow Channels of Water Flooding in Ultra-High Water Cut Reservoirs

The water drive reservoir in Shengli Oilfield has entered a stage of ultra-high water cut development, forming an advantageous flow channel for the water drive, resulting in the inefficient and ineffective circulation of injected water. Therefore, the distribution characteristics of water drive flow channels and their controlled residual oil in ultra-high water cut reservoirs are of great significance for treating water drive dominant flow channels and utilizing discontinuous residual oil. Through microscopic physical simulation of water flooding, color mixing recognition and image analysis technology were used to visualize the evolution characteristics of water flooding seepage channels and their changes during the control process. Research has shown that during the ultra-high water content period, the shrinkage of the water drive seepage channel forms a dominant seepage channel, forming a “seepage barrier” at the boundary of the dominant seepage channel, and dividing the affected area into the water drive dominant seepage zone and the seepage stagnation zone. The advantage of water flooding is that the oil displacement efficiency in the permeable zone is as high as 80.5%, and the remaining oil is highly dispersed. The water phase is almost a single-phase flow, revealing the reason for high water consumption in this stage. The remaining oil outside the affected area and within the stagnant flow zone accounts for 89.8% of the remaining oil, which has the potential to further improve oil recovery in the later stage of ultra-high water cut. For the first time, the redundancy index was proposed to quantitatively evaluate the control effect of liquid extraction and liquid flow direction on the dominant flow channels in water flooding. Experimental data showed that both liquid extraction and liquid flow direction can regulate the dominant flow channels in water flooding and improve oil recovery under certain conditions. Microscopic physical simulation experiments were conducted through the transformation of well network form in the later stage of ultra-high water content, which showed that the synergistic effect of liquid extraction and liquid flow direction can significantly improve the oil recovery effect, with an oil recovery rate of 68.02%, deepening the understanding of improving oil recovery rate in the later stage of ultra-high water content.