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. 2026 Jan 29;11(5):8616–8628. doi: 10.1021/acsomega.5c11911

Optimization of Chemical Flooding Injection System and Enhanced Oil Recovery after Water Flooding in Block J16, Liaohe Oilfield

Fei Guo †, Junfeng Wang ‡,*, Shuaishuai Zhao ‡,*, Chuanmin Xiao †, Xiaofeng Li †, Yanfu Pi ‡, Li Liu ‡
PMCID: PMC12902855  PMID: 41696314

Abstract

To address the pronounced heterogeneity and preferential water channeling through high-permeability zones in the medium- to high-permeability reservoirs of Block J16, Liaohe Oilfieldfactors that constrain recovery and limit the effectiveness of water floodingthis study systematically investigates chemical-flooding strategies for enhanced oil recovery. We conducted a comprehensive characterization of the supplied polymer (L-PAM), surfactant, and pre-cross-linked gel particles (PPG). Using a large-scale, three-dimensional heterogeneous physical model, we compared the displacement performance of a binary composite system (polymer + surfactant) and a heterogeneous composite system (polymer + surfactant + PPG). Experimental results show that L-PAM exhibits satisfactory thermal stability, salt tolerance, and long-term property retention. The binary system attains ultralow interfacial tension, whereas the heterogeneous system markedly enhances viscoelastic characteristics. Oil-displacement experiments indicate that the heterogeneous + binary composite system delivers the best recovery outcome, achieving a final recovery of 77.75%, representing an improvement of approximately 28.7% over conventional water flooding. By effectively plugging high-permeability channels, this system substantially improves sweep efficiency in medium- and low-permeability zones and reduces water cut by up to 36.49%. Monitoring of oil-saturation distribution further confirms that the heterogeneous + binary system promotes fluid diversion and profile modification through physical plugging and flow-path alteration, thereby increasing fluid intake in medium- and low-permeability layers. These findings provide experimental evidence and technical guidance for the design and optimization of chemical-flooding strategies for field application.

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1. Introduction

With ongoing field development, most mature oilfieldsincluding Block J16 in the Liaohe Oilfieldhave reached high or ultrahigh water-cut stages, with overall water cut typically exceeding 90%. − Prolonged water flooding exacerbates reservoir heterogeneity and fosters the formation of preferential flow channels. − As injected water follows these high-permeability pathways, residual oil becomes highly dispersed and is difficult to mobilize effectively by conventional waterflooding. − Consequently, chemical flooding has emerged as a pivotal technology for incremental oil recovery. Polymer flooding, a widely used chemical EOR technique, primarily increases the viscosity of the injected phase and improves the oil–water mobility ratio. − This mechanism suppresses viscous fingering and enhances macroscopic sweep efficiency, typically yielding substantial gains in crude-oil recovery in field applications. However, in strongly heterogeneous reservoirs such as Block J16, polymer flooding remains constrained by several important limitations. First, polymer solutions are susceptible to shear degradation, adsorption, and retention during transport through porous media, which reduce viscoelasticity and markedly impair displacement performance. Second, reliance on viscosity control alone is often insufficient to plug established preferential channels effectively, and field performance may therefore fall short of theoretical expectations. Accordingly, systematic experimental investigation and targeted technological development are imperative during the design and evaluation phases of polymer-flooding projects to improve overall displacement efficiency and to validate applicability under site-specific reservoir conditions.

In response to increased reservoir heterogeneity and the progressively complex, dispersed distribution of residual oil after water flooding, numerous researchers have undertaken systematic investigations of mitigation strategies. − Sang et al. demonstrated that precross-linked gel particles (PPG) effectively mitigate reservoir heterogeneity and substantially enhance oil recovery in low-permeability zones, with efficacy increasing as heterogeneity intensifies. Bai et al. reported that PPG exhibits favorable viscoelasticity, compressive strength, and water-retention capacity upon hydration and swelling, while offering operational advantages including simple preparation, procedural flexibility, excellent thermal and salinity tolerance, and minimal formation damage. Zhao et al. examined the restart pressure gradient of preformed particle gels during transit through pore throats and established a framework to characterize their “plugging–deformation–restart” migration mechanism; subsequent microscopic experiments have substantiated these mechanistic behaviors. Related studies confirm that heterogeneous displacement schemes employing preformed or branched particles achieve marked effectiveness in water control and production stabilization. Li et al. employed three-dimensional physical modeling coupled with NMR to compare sweep and displacement efficiencies for water flooding, polymer flooding, and functional-polymer flooding, concluding thateven when sweep efficiency is limitedimproving displacement efficiency is essential for enhancing ultimate recovery. To address postpolymer-flood performance degradation, Liu et al. developed a surfactant–polymer formulation incorporating biosurfactants; microfluidic tests, NMR core-flood experiments, and numerical simulation demonstrated that the formulation synergistically improves oil displacement via fluid diversion and sweep-volume expansion, with flow-pattern intensification and directional adjustment further augmenting performance while residual polymer aids sweep enlargement. Zhang et al. showed that branched preformed particle gel (B-PPG) heterogeneous composite flooding effectively reduces water cut and increases recovery: well-pattern densification and adjustment redirect dominant flow paths and enhance displacement effectiveness, while coexisting residual polymers synergistically enlarge the swept volume. An et al. analyzed production dataincluding water-cut trends, flow resistance, and injection profilesto evaluate production performance and residual-oil mobilization during polymer–surfactant–PPG composite flooding following polymer flooding, and proposed tailored displacement mechanisms (e.g., pattern infilling and injection-profile modification) targeted to specific residual-oil distributions.

Although extensive research has highlighted the benefits of optimizing injection strategies and composite-flooding systems, most studies have concentrated on the formulation of displacement agents and their laboratory performance. − Systematic comparative investigations tailored to specific reservoir blocks are still scarce. In particular, at the three-dimensional scalewhen accounting for both interlayer and intralayer heterogeneity and their coupling effectsa comprehensive quantitative assessment of displacement efficiency and a mechanistic evaluation of different composite systems (including conventional binary systems, heterogeneous composite systems, and conformance-control pretreatment combined with binary systems) remain inadequate. ,

Drawing on the development status of Block J16 in the Liaohe Oilfield, existing studies of polymers and surfactants, and field-trial experience, this study introduces precross-linked gel particles (PPG) matched to the reservoir’s permeability contrast to formulate a composite injection system tailored for the target block. Using three-dimensional physical simulation experiments, we compared the displacement performance of several composite schemes: a conventional binary system (polymer + surfactant), a heterogeneous composite incorporating PPG with the binary system, and a conformance-control pretreatment combined with binary flooding. The study systematically elucidates the mechanisms by which these systems promote fluid diversion and improve recovery from medium- to low-permeability zones, and identifies the optimal chemical-flooding formulation and injection parameters compatible with the geological characteristics of Block J16. The results provide experimental validation and theoretical support for the design and field implementation of chemical-flooding strategies in Block J16 and in analogous, strongly heterogeneous reservoirs.

2. Experimental Section

2.1. Chemicals and Reagents

The polymer (L-PAM, molecular weight: 25 × 106 Da), surfactant, and precross-linked gel particles (PPG) were supplied by the Research Institute of Exploration and Development, Liaohe Oilfield. Deionized water was prepared in the laboratory. Reagents including Na2SO4, NaCl, Na2CO3, NaHCO3, CaCl2, and MgCl2·6H2O, all of analytical purity, were procured from Shanghai Aladdin Biochemical Technology Co., Ltd. Artificial heterogeneous core samples were fabricated in-house. The PPG particles, with a particle size distribution of 0.15–0.20 mm, were provided by the Research Institute of Exploration and Development, Liaohe Oilfield. Under experimental conditions at 65 °C, the PPG particles undergo controlled aqueous swelling, achieving a stable expansion ratio of approximately 3. The measured compressive strength was determined to be 1.7 MPa.

Simulated formation water was prepared based on the ionic composition representative of the Liaohe Oilfield formation water, with a total salinity of 2,749 mg/L. This simulated brine was primarily utilized for core saturation procedures during the experimental sequence. The detailed ionic composition is provided in Table .

1. Reagent and Dosage Used for the Simulated Formation Water with a Salinity of 2749 mg/L.

reagent Na2SO4 NaCl Na2CO3 NaHCO3 CaCl2 MgCl2·6H2O
concentration (mg/L) 13.9 385.8 53.9 2262 13.58 41.82
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2.1.1. Experimental Oil

Simulated oil was formulated by blending dehydrated crude oil from Liaohe Oilfield with aviation kerosene at proportions determined by experimental requirements. The kinematic viscosity of the prepared oil measured 30 mPa·s at 65 °C.

2.1.2. Experimental Core

A reverse-rhythm planar heterogeneous physical model was fabricated based on the porosity-permeability characteristics and permeability grading of Block J16 in Liaohe Oilfield. The model dimensions are 60 cm × 60 cm × 4.5 cm, featuring a vertically stratified heterogeneous configuration with three layers of equal thickness. The respective permeabilities of the three layers are 1000 × 10–3, 2000 × 10–3, and 3500 × 10–3 μm2. A physical photograph of the planar heterogeneous model is presented in Figure .

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Schematic diagram of the three-layer heterogeneous model.

2.2. Instrumentation

The principal instrumentation employed in this investigation comprised: a Brookfield DV-III viscometer (Brookfield Engineering Laboratories, USA); a TX-500 interfacial tensiometer (Beijing Aodelinuo Instrument Co., Ltd., China); an MCR-302 high-temperature high-pressure (HTHP) rheometer (Anton Paar GmbH, Austria); an iHDAS-II intelligent deoxygenation apparatus (Beijing Donghang Keyi Instrument Co., Ltd., China); a laboratory-customized real-time oil saturation monitoring system; and a HYCAL multifunctional HTHP core flooding apparatus (HYCAL Engineering, Canada).

2.3. Methods

2.3.1. Viscosity-Increasing Property Test

A series of L-PAM aqueous solutions with varying mass concentrations were prepared using simulated formation water as the base fluid. The solutions were vigorously agitated and subsequently aged until complete bubble dissipation. The apparent viscosity of each solution was then determined at 65 °C employing a Brookfield DV-III viscometer equipped with a No. 0 rotor at 6 rpm, to evaluate the viscosity-enhancing characteristics of the polymer solutions.

2.3.2. Temperature Resistance Test

A 2000 mg/L L-PAM solution was prepared using simulated formation water as the solvent. The apparent viscosity of the solution was subsequently determined across a temperature range of 25–85 °C employing a Brookfield DV-III viscometer, with the resultant viscosity-temperature profile constructed to systematically evaluate the thermal stability of the polymer solution.

2.3.3. Salt Tolerance Test

A 2000 mg/L L-PAM solution was formulated using simulated formation water as the base solvent. The influence of varying total salinity multiples (0, 0.5, 1.0, 1.5, 2.0, 2.5, 3.0, 3.5) on the apparent viscosity of the polymer solution was systematically investigated at 65 °C to comprehensively evaluate its salt tolerance characteristics.

2.3.4. Shear Resistance Characterization

A 2000 mg/L L-PAM solution was formulated using simulated formation water as the solvent medium. The solution was subjected to rheological characterization at a constant temperature of 65 °C using a high-temperature, high-pressure rheometer. The variation of viscosity with applied shear rate was systematically recorded, and the corresponding viscosity-shear rate profile was constructed to quantitatively evaluate the shear resistance behavior of the polymer solution.

2.3.5. Long-Term Stability

A 2000 mg/L L-PAM solution was prepared using simulated formation water as the solvent medium. The solution was transferred into ampules, deoxygenated, and subsequently flame-sealed. These sealed ampules were then subjected to static aging in a constant-temperature oven maintained at 65 °C for a duration of 70 days. The viscosity of the solution was systematically measured at 5-day intervals throughout the aging period, and the corresponding viscosity retention profile was constructed to evaluate the long-term stability of the polymer solution under simulated reservoir conditions.

2.3.6. Interfacial Tensiometry

Two 2000 mg/L L-PAM solutions were separately prepared, with one formulation incorporating 0.25 wt % surfactant. The oil–water interfacial tension was subsequently determined at 65 °C using a TX-500 interfacial tensiometer, employing simulated crude oil as the oleic phase and simulated formation water as the aqueous phase.

2.3.7. Viscoelastic Characterization

Two separate 2000 mg/L L-PAM solutions were prepared, with one formulation incorporating 0.1 wt % precross-linked gel particles (PPG). Oscillatory frequency sweep tests were conducted at 65 °C using an MCR-302 rotational rheometer to determine the storage modulus (G′) and loss modulus (G″) of each system, thereby characterizing their viscoelastic properties.

2.4. Displacement Efficiency

To enhance the development efficiency of chemical flooding following water flooding in Block J16 of Liaohe Oilfield, this study designed three distinct displacement systems: a binary system, a heterogeneous composite system, and a conformance control pretreatment followed by binary flooding. Utilizing a large-scale three-dimensional physical model (core parameters detailed in Table ) integrated with a real-time oil saturation monitoring system, we systematically evaluated the displacement performance of each system to identify the optimal chemical flooding strategy for the target reservoir. The experimental setup is illustrated in Figure , with specific testing protocols summarized in Table . During the experiments, reflecting the actual production characteristics of Block J16, water flooding was initially conducted until the recovery factor reached 49–50%, followed by chemical system injection, and concluding with subsequent water flooding to comprehensively assess both the enhanced oil recovery potential and follow-up development capacity of the chemical flooding systems.

2. Specific Parameters of the Three-Layer Heterogeneous Core Well-Pattern Model.

core number L × W × H (cm) permeability (×10–3 μm2) porosity (%) oil saturation (%)
1 60 × 60 × 4.5 low permeability layer: 1000 27.08 72.60
intermediate permeability layer: 2000
high permeability layer: 3500
2 60 × 60 × 4.5 low permeability layer: 1000 27.23 71.99
intermediate permeability layer:2000
high permeability layer: 3500
3 60 × 60 × 4.5 low permeability layer: 1000 26.51 72.76
intermediate permeability layer:2000
high permeability layer: 3500
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Schematic of the experimental setup for injection strategy optimization using a three-dimensional physical model.

3. Experimental Program Designed for the Three-Dimensional Physical Model .

experiment no. injection system injection scheme
1 binary flooding waterflooding until recovery reaches 49–50% + 0.1PV 0.21%P + 0.7PV (0.25%S + 0.20%P) binary flooding + 0.2PV (0.20%S + 0.20%P) binary flooding + 0.15PV 0.14%P + subsequent waterflooding until water cut 98%
2 heterogeneous flooding waterflooding until recovery reaches 49–50% + 0.1PV (0.14%P + 0.1%PPG) + 0.7PV (0.12%P + 0.25%S + 0.1%PPG) composite-system flooding + 0.2PV (0.12%P + 0.20%S + 0.1%PPG) composite-system flooding + 0.15PV 0.14%P + subsequent waterflooding until water cut 98%
3 profile control flooding + binary flooding waterflooding until recovery reaches 49–50% + 0.1PV (0.21%P + 0.1%PPG) + 0.7PV (0.2%P + 0.25%S) composite-system flooding + 0.2PV (0.2%P + 0.20%S) composite-system flooding + 0.15PV 0.14%P + subsequent waterflooding until water cut 98%
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a

L-PAM: P; surfactant: S; pore volume: PV.

The experimental procedure used to determine oil-displacement efficiency in the three-dimensional physical model comprised the following steps:

  • 1.

    The 3D physical model was evacuated under vacuum for 36–48 h until the internal pressure reached −0.1 MPa, then saturated with simulated formation water; porosity was calculated from the saturated water volume, and the model was connected to the experimental apparatus.

  • 2.

    Simulated oil was injected at a constant rate of 1 mL·min–1 until no aqueous phase was produced at the outlet, indicating completion of oil saturation; initial oil saturation was calculated from the produced water volume.

  • 3.

    Waterflooding was performed at the same injection rate with continuous monitoring of injection pressure and effluent production; flooding continued until the target waterflood recovery was achieved.

  • 4.

    Chemical composite systems were injected at the same rate according to the prescribed pore-volumes listed in Table . Injection pressure and production data were recorded, and interlayer saturation distribution was measured with the oil-saturation monitoring system after each injection stage.

  • 5.

    Postchemical waterflooding was continued until effluent water cut reached 98%, marking the end of the experimental sequence.

  • 6.

    The entire protocol was repeated for all designated scenarios.

3. Results and Discussion

3.1. Viscosity Enhancement Test

To evaluate the viscosity-enhancing performance of the polymer, an L-PAM solution with a mass concentration of 2000 mg/L was prepared using simulated formation water. The apparent viscosity was measured at 65 °C using a Brookfield DV-III viscometer (with rotor No. 0 at 6 rpm), with the results presented in Figure . As illustrated, the apparent viscosity of the L-PAM solution progressively increases with rising mass concentration. When the concentration exceeds 1500 mg/L, the system exhibits a pronounced viscosity-enhancing capability. As the concentration is further elevated, the increased branching of polymer chains enhances intermolecular interactions, leading to the formation of larger molecular aggregates and consequently a more substantial viscosity enhancement. At the concentration of 2000 mg/L, the solution achieves an apparent viscosity of 52 mPa·s, demonstrating favorable viscosity-enhancing characteristics of L-PAM under these conditions.

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Correlation between polymer solution viscosity and polymer concentration.

3.2. Thermal Stability Assessment

As illustrated in Figure , the apparent viscosity of the L-PAM solution progressively diminishes with increasing temperature. At lower temperatures, the hydration groups within the L-PAM molecular chains form relatively stable hydrogen bonds with water molecules, resulting in enhanced chain extension and consequently higher apparent viscosity. As the temperature rises, the hydrogen bonding interactions weaken, promoting gradual chain coiling and subsequent viscosity reduction. Concurrently, elevated temperatures intensify the thermal motion of both polymer segments and water molecules, facilitating intersegmental slippage and correspondingly reducing chain entanglement, which further contributes to the decline in apparent viscosity. At 65 °C, the L-PAM solution maintains an apparent viscosity of 52 mPa·s with a viscosity retention rate exceeding 60%, demonstrating its capability to preserve substantial viscosity under medium-high temperature conditions and confirming satisfactory thermal stability.

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Variation of polymer solution viscosity with temperature.

3.3. Salt Tolerance Evaluation

The presence of various metal salt ions in formation water exerts significant influence on the viscosity of polymer solutions, a phenomenon commonly referred to as salt-sensitivity. To evaluate the salt tolerance of L-PAM, solutions with a concentration of 2000 mg/L were prepared using simulated formation waters of different salinities. The apparent viscosity was measured at 65 °C using a rotational viscometer, with results presented in Figure . As the salinity of the simulated formation water increases, the apparent viscosity of the L-PAM solution progressively diminishes. This phenomenon arises from the compression of the double electrical layer within the L-PAM hydration shell by salt ions, which enhances electrostatic repulsion forces, consequently reducing the hydrodynamic volume of polymer molecules and promoting molecular chain coiling, thereby decreasing the system’s apparent viscosity. When the salinity reaches 10,000 mg/L, the solution maintains a viscosity retention rate of 60%, demonstrating favorable salt tolerance characteristics of the L-PAM polymer.

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Performance evaluation of polymer by simulated oilfield water.

3.4. Shear Resistance Characterization

Figure illustrates the relationship between polymer solution viscosity and linearly varying shear rates. The L-PAM solution demonstrates pronounced shear-thinning behavior, with its apparent viscosity progressively decreasing with increasing shear rate. Within the shear rate range of 0.1–45 s–1, the supramolecular interactions maintaining the three-dimensional network structure are progressively disrupted, resulting in diminished structural integrity. As the rate of structural disruption exceeds that of reformation, viscosity reduction occurs. When the shear rate exceeds 45 s–1, conformational changes in the polymer chains lead to enhanced chain extension and intensified intermolecular friction, consequently moderating the viscosity decline rate. Furthermore, the ultimate viscosity maintains elevated values with increasing solution concentration.

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Evaluation of shear properties of polymers.

3.5. Long-Term Stability Analysis

The viscosity stability of polymer solutions serves as a critical parameter for evaluating the long-term performance of oil displacement systems in reservoir porous media, with its retention capacity under reservoir conditions directly governing the effective viscosity and displacement efficiency. This study investigated the temporal viscosity evolution of L-PAM at 65 °C, with results presented in Figure . As depicted, the polymer solution exhibits gradual viscosity reduction over time. A relatively pronounced viscosity decline was observed during the initial 30-day period, with a retention rate of 60.38%. After 70 days of aging, the solution maintained a viscosity of 19.2 mPa·s with a retention rate of 36.92%, demonstrating satisfactory long-term thermal stability of the L-PAM polymer under simulated reservoir conditions.

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Evaluation of aging resistance of polymers.

3.6. Interfacial Tension Measurement

The polymer–surfactant (P–S) binary system synergistically combines the viscosity-enhancing properties of polymers with the interfacial tension-reducing capability of surfactants. This integrated approach not only expands the sweep efficiency but also improves the displacement efficiency, thereby significantly enhancing overall crude oil recovery. As illustrated in Figure , while the interfacial tension (IFT) between a pure L-PAM solution and crude oil measures 37 mN/m, the incorporation of surfactant into the L-PAM + S binary system markedly reduces the IFT to the order of 10–2 mN/m. These results demonstrate that the formulated binary system exhibits excellent ultralow interfacial tension performance, providing fundamental mechanistic support for the effectiveness of chemical flooding.

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Curves of interfacial tension versus time at a 2000 mg/L concentration of two solutions.

3.7. Viscoelastic Behavior Evaluation

Viscoelastic properties serve as crucial rheological parameters for characterizing the plugging and profile modification capabilities of displacement systems, where the storage modulus (G′) reflects the elastic behavior and structural strength of the system, while the loss modulus (G″) characterizes its viscous response. Through oscillatory frequency sweep tests, this study conducted a comparative investigation of the modulus variations between the L-PAM + S binary system and the L-PAM + S + PPG composite system formed by incorporating precross-linked gel particles (PPG). The results, presented in Figure , demonstrate that under identical concentration and frequency conditions, both G′ and G″ values of the L-PAM + S + PPG composite system significantly exceed those of the binary system. This indicates that the incorporation of PPG effectively enhances the viscoelasticity of the system, thereby contributing to improved plugging and fluid diversion capabilities in actual reservoir applications.

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Viscoelastic response curves of the L-PAM + S + PPG and L-PAM + S systems.

3.8. Evaluation of Oil-Displacement Efficiency

3.8.1. Dynamic Production Curve

Using a three-dimensional physical model, chemical flooding experiments were systematically conducted after water flooding to evaluate the enhanced oil recovery (EOR) performance of three chemical systemsbinary (B), heterogeneous composite (HC), and conformance control pretreatment plus binary (CCP + B)in a heterogeneous reservoir. Dynamic production profiles (Figures –) show that during water flooding, all three systems exhibited similar behavior in recovery factor, injection pressure, and water cut. In the initial displacement stage, injected water effectively mobilized crude oil under initial oil saturation, leading to a period of water-free oil production and a rapid rise in recovery. As flooding continued, the strong mobility contrast between water and oil created an unfavorable mobility ratio, promoting preferential flow in high-permeability zones. After water breakthrough, subsequently injected water largely recirculated ineffectively through these channels, sharply increasing the water cut and slowing recovery growth. Chemical flooding commenced when waterflood recovery reached approximately 49%.

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Evolution of oil recovery, water cut, and injection pressure as a function of cumulative injected pore volumes (binary system).

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Evolution of oil recovery, water cut, and injection pressure as a function of cumulative injected pore volumes (profile control combined with the binary flooding system).

Figure shows the displacement behavior of the binary system. During this stage, the maximum injection pressure reached 0.134 MPa, accompanied by a notable water cut reduction of 29.24%, and an incremental oil recovery of 20.63% was achieved in the chemical flooding phase. Injection of the 0.1 PV prepolymer slug did not significantly improve oil recovery; however, a slight decrease in water cut and a marked rise in injection pressure were observed. These responses indicate that polymer molecules primarily entered high-permeability channels, increasing flow resistance through adsorption and mechanical entrapment, thereby diverting flow to medium- and low-permeability zones and preliminarily improving the fluid intake profile. Subsequent injection of the 0.7 PV main binary slug led to a substantial water cut reduction (maximum 29.24%) and a simultaneous increase in oil recovery. This result reflects the dual mechanisms of the binary system: profile control and interfacial tension reduction. The system preferentially enters unswept regions, improving macroscopic sweep efficiency, while significantly lowering oil–water interfacial tension to enhance microscopic displacement efficiency. After chemical flooding, the final recovery factor reached 70.24%, with an incremental recovery of 20.63% attributed to the chemical flooding stage.

Figure shows the displacement behavior of the heterogeneous composite system. During this stage, the maximum injection pressure reached 0.202 MPa, accompanied by a water cut reduction of 36.49% and an incremental recovery of 28.70%. Injection of the 0.1 PV L-PAM + PPG preslug induced a substantial pressure increase but no significant recovery improvement, although water cut decreased moderately. PPG particles physically blocked high-permeability channels, working synergistically with the high-viscosity polymer to improve mobility control. This process significantly increased flow resistance in high-permeability zones, thereby reconstructing the fluid intake profile and establishing a balanced displacement environment for subsequent main slug injection. Injection of the 0.7 PV heterogeneous composite main slug then substantially reduced water cut while simultaneously improving oil recovery. Throughout this stage, PPG provided continuous deep profile modification, the polymer optimized the mobility ratio to expand sweep efficiency in medium-low permeability zones, and the surfactant effectively reduced oil–water interfacial tension, thereby synergistically improving both microscopic displacement efficiency and macroscopic sweep efficiency. The graded concentration design of the system ensured stable displacement front advancement and prevented early breakthrough. The model ultimately achieved a total recovery of 77.75%, with 28.70% incremental recovery during this stage. These results demonstrate that the heterogeneous composite system significantly enhances development effectiveness in heterogeneous reservoirs through coordinated deep fluid diversion and interfacial tension control.

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Evolution of oil recovery, water cut, and injection pressure as a function of cumulative injected pore volumes (heterogeneous system).

The displacement characteristics of the conformance control + binary system are illustrated in Figure . During this phase, the maximum injection pressure reached 0.154 MPa with a water cut reduction of 35.64%, achieving an incremental recovery of 24.57%. Following the injection of 0.1 PV L-PAM + PPG preslug, a significant pressure increase was observed without substantial changes in recovery factor or water cut, indicating effective plugging of high-permeability channels by PPG particles and subsequent deep fluid diversion. This process, synergistically enhanced by the high-viscosity polymer, increased flow resistance and achieved fluid intake profile reconstruction. Subsequent injection of 0.7 PV conformance control + binary main slug resulted in remarkable water cut reduction and simultaneous recovery improvement. During this stage, the polymer optimized mobility ratio to stabilize the displacement front and expand sweep volume in medium-low permeability zones, while the surfactant achieved ultralow interfacial tension, effectively stripping oil films from rock surfaces and emulsifying residual oil clusters, thereby significantly enhancing displacement efficiency. The balanced flow field established by the preslug provided fundamental conditions for synergistic enhancement of the binary system. After chemical flooding, the model achieved a final recovery of 73.95% with an incremental recovery of 24.57%. The graded concentration design ensured overall stability throughout the displacement process. In summary, all three chemical flooding systems substantially enhanced development effectiveness in postwaterflood heterogeneous reservoirs. The heterogeneous composite system demonstrated optimal performance in coordinated deep fluid diversion and interfacial tension control, achieving the highest incremental recovery (28.70%), followed by the conformance control + binary system (24.57%) and the binary system (20.63%). These experimental results provide critical reference for chemical flooding system optimization in field applications.

3.8.2. Planar Saturation Distribution

The entire displacement process was monitored using a real-time oil saturation monitoring system. Integration of resistivity-oil saturation calibration curves with Surfer software enabled visualization of oil saturation distribution across different permeability layers at various displacement stages, as shown in Figures –. After water flooding, preferential flow pathways had developed along the main streamlines in the high-permeability layer. This occurs because injected water preferentially enters high-permeability zones due to their lower flow resistance. Combined with water’s low viscosity, this preferential flow promotes viscous fingering, causing rapid water breakthrough at the production end and forming continuous water channels through high-permeability layers. Subsequently injected water mainly flowed through these established pathways, effectively draining extensive areas of the high-permeability layer but leaving medium- and low-permeability zones substantially underutilized. Specifically, although the medium-permeability layer developed preliminary connected flow paths between injector and producer, oil saturation within these channels remained above 30%, while surrounding regions typically exceeded 35%. In the low-permeability layer, noticeable oil saturation reduction was limited to areas near the injection well, with most regions maintaining saturation above 45%. Zones distant from the injection well largely retained initial oil saturation, confirming substantial bypassed residual oil after water flooding.

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Evolution of oil saturation across different permeability layers at various stages of the 3D physical model (Scheme 1: binary flooding).

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Evolution of oil saturation across different permeability layers at various stages of the 3D physical model (Scheme 3: profile control combined with binary flooding).

Figure demonstrates that after injecting the main binary system slug, sweep efficiency further increased in the high-permeability layer, indicating effective fluid diversion into previously poorly swept zones. Meanwhile, the considerable oil saturation reduction in swept areas confirms that the binary system enhances microscopic displacement efficiency by significantly reducing oil–water interfacial tension. Significant saturation decreases also occurred in medium- and low-permeability layers: connectivity improved along main flow paths in the medium-permeability layer, while crude oil in primary and adjacent channels within the low-permeability layer was effectively mobilized. Grid-based analysis indicated that during water flooding, recovery factors reached 67.47% in the high-permeability layer but only 30.74% in the low-permeability layer, with substantial remaining oil accumulation zones flanking the main flow paths. After binary system flooding, recovery increased by 14.62% in the high-permeability layer and 21.42% in the low-permeability layer, confirming the system’s effectiveness in modifying the fluid intake profile and enhancing intake capacity in medium- and low-permeability zones. Additionally, oil saturation along main flow channels in the medium-permeability layer approached residual levels, further validating the binary system’s high displacement efficiency. In summary, through polymer–surfactant synergy, the binary system combines profile control with displacement enhancement, substantially expanding sweep volume while significantly reducing residual oil saturation, thereby significantly enhancing overall recovery in postwater-flood heterogeneous reservoirs.

Figure demonstrates that following the injection of the main heterogeneous composite system slug, the sweep efficiency within the high-permeability layer of the model further increased. This observation indicates that the heterogeneous components effectively plugged high-permeability channels, redirecting fluid flow toward regions previously poorly swept by water flooding. Concurrently, the significant reduction in oil saturation in the swept areas confirms that the system substantially enhances displacement efficiency through the synergistic mechanism of “heterogeneous profile modification - polymer-enhanced sweep efficiency - surfactant-induced tension reduction.” A pronounced decrease in oil saturation was also observed in the medium- and low-permeability layers: the medium-permeability layer developed effective flow channels along the main streamlines, while the low-permeability layer exhibited substantially improved mobilization of crude oil in the primary flow regions. During the water flooding stage, the recovery factors were 67.45 and 31.06% for the high- and low-permeability layers respectively, with significant remaining oil accumulation zones evident on both sides of the main flow paths. After heterogeneous composite system flooding, the high-permeability layer showed an 18.44% increase in recovery, while the low-permeability layer demonstrated a 28.89% enhancement. These results indicate that the system effectively modifies the fluid intake profile across all layers and significantly improves the liquid intake capacity of medium- and low-permeability zones. The fundamental mechanism involves physical plugging of high-permeability channels and fluid diversion by heterogeneous components. Furthermore, the oil saturation along the main flow channels in the medium-permeability layer declined to residual oil levels, providing additional validation of the system’s high displacement efficiency. Upon completion of the displacement process, the continuous expansion of sweep efficiency in the medium- and low-permeability layers demonstrates that, through the coordinated action of heterogeneous profile control agents, polymers, and surfactants, the system achieves both deep profile modification and efficient oil displacement. Consequently, it significantly enhances the ultimate recovery factor of postwater-flood heterogeneous reservoirs.

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Evolution of oil saturation across different permeability layers at various stages of the 3D physical model (Scheme 2: heterogeneous flooding).

Figure demonstrates that following the injection of the main conformance control + binary system slug, the sweep efficiency within the high-permeability layer significantly improved, indicating that effective plugging of high-permeability channels by PPG particles redirected fluid flow toward previously under-swept regions, thereby optimizing the flow field distribution. Concurrently, the substantial reduction in oil saturation in swept areas reflects the system’s synergistic mechanism of “PPG deep profile control - polymer-enhanced sweep efficiency - surfactant-induced interfacial tension reduction,” which simultaneously improves both macroscopic sweep efficiency and microscopic displacement efficiency. A notable decrease in oil saturation was also observed in medium- and low-permeability layers: well-connected flow pathways developed along main streamlines in the medium-permeability layer, while the low-permeability layer exhibited effective crude oil mobilization in primary flow regions. During water flooding, recovery factors reached 67.39 and 30.85% in high- and low-permeability layers respectively, with significant remaining oil accumulation observed on both sides of dominant flow paths. After conformance control + binary system flooding, recovery increased by 16.97% in the high-permeability layer and 27.12% in the low-permeability layer, demonstrating the system’s effectiveness in modifying the fluid intake profile across all layers and significantly enhancing liquid intake capacity in medium- and low-permeability zones. The fundamental mechanism involves physical plugging of high-permeability channels and fluid diversion by PPG particles. Furthermore, oil saturation along main flow channels in the medium-permeability layer declined to residual levels, confirming the system’s excellent displacement efficiency. The continuous expansion of sweep efficiency in medium- and low-permeability layers after flooding comprehensively demonstrates the synergistic effects of PPG plugging and diversion, polymer viscosity enhancement for improved sweep, and surfactant emulsification for enhanced oil displacement. These results indicate that the conformance control + binary system substantially improves ultimate recovery in postwater-flood heterogeneous reservoirs.

3.8.3. Production Characteristics of Different Layers in the 3D Physical Model under Various Injection Systems

Table presents the displacement and sweep efficiencies for different layers in the three-dimensional physical model under various injection systems. The binary system increased sweep efficiency by 7.75, 20.12, and 28.56% in the high-, medium-, and low-permeability layers, respectively. The conformance-control-binary system showed corresponding improvements of 8.50, 26.87, and 34.90%, while the heterogeneous composite system achieved enhancements of 10.69, 28.50, and 37.19%. The heterogeneous composite system yielded the highest sweep efficiency improvement across all layers, indicating its superior ability to modify the fluid intake profile and enhance liquid intake capacity in medium- and low-permeability zones, thereby expanding the swept volume in each layer. Subsequently, this system increased recovery factors by 18.44, 32.36, and 30.89% in the high-, medium-, and low-permeability layers, respectively.

4. Comparison of Displacement Efficiency and Areal Sweep Factor of the 3D Physical Model under Different Injection Schemes.

3.8.3.

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In summary, the heterogeneous composite system effectively restructures the fluid intake profile in postwaterflood heterogeneous reservoirs and substantially increases recovery efficiency by enhancing fluid intake capacity in medium- and low-permeability zones. This system achieves an incremental recovery of 28.70%, outperforming both the binary system and the conformance-control-binary system. An integrated analysis of recovery performance, water-cut behavior, and oil mobilization characteristics across different permeability layers demonstrates that the heterogeneous composite system represents the optimum injection strategy.

4. Conclusions

To address the technical challenges associated with enhancing oil recovery from postwaterflood heterogeneous reservoirs in Block J16 of the Liaohe Oilfield, this study conducted a comprehensive performance evaluation of three chemical flooding systems. Fundamental property assessments of the polymer, surfactant, and precross-linked gel particles (PPG), along with oil displacement experiments performed on a three-layer heterogeneous physical model, lead to the following conclusions:

  • 1.

    The L-PAM polymer demonstrates effective viscosity-enhancing characteristics, along with good thermal stability and salt tolerance. At 65 °C, the 2000 mg·L–1 L-PAM solution exhibited an initial apparent viscosity of 52 mPa·s and retained about 60% of this initial value in the short term test (measured after equilibration). After 70 days of static aging at 65 °C, viscosity decreased to 19.2 mPa·s, corresponding to a long-term retention of 36.92%.

  • 2.

    The L-PAM + PPG composite system exhibits higher elastic (G′) and viscous (G″) moduli than the single L-PAM system, confirming that PPG incorporation enhances system viscoelasticity. Meanwhile, the L-PAM-surfactant binary system reduces oil–water interfacial tension to an ultralow value of 10–2 mN/m.

  • 3.

    Three-dimensional physical model tests demonstrate that the heterogeneous composite system provides the highest EOR performance, achieving 28.70% incremental recovery. Displacement efficiencies reach 89.49, 83.14, and 71.02% in the high-, medium-, and low-permeability layers, respectively, with corresponding sweep efficiencies of 95.98, 89.75, and 87.23%. The conformance-control-binary and conventional binary systems yield lower incremental recoveries of 24.57 and 20.63%, respectively. The heterogeneous system demonstrates superior performance in fluid intake profile modification and swept-volume expansion.

Acknowledgments

This work was supported by the National Major Science and Technology Special Project 6: “Demonstration of Classification and Adjustment for High-Temperature and High-Salinity Thin Interbedded Reservoirs in Liaohe Depression” (Project No.: 2025ZD1407106).

All data generated or analyzed during this study are included in this published article.

F.G., J.W., and S.Z. conceptualized and designed the experiments and contributed to the first manuscript draft; C.X., X.L., Y.P., and L.L. analyzed the data, wrote and edited the manuscript. All authors edited and revised the manuscript critically and agreed to submit it to this journal.

The authors declare no competing financial interest.

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Data Availability Statement

All data generated or analyzed during this study are included in this published article.

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