Experimental Study on Surfactant–Polymer Flooding After Viscosity Reduction for Heavy Oil in Matured Reservoir

Abstract

An advanced enhanced oil recovery (EOR) method was investigated, employing a surfactant–polymer (SP) system in combination with a viscosity reducer for application in a heavy oil reservoir within the Haiwaihe Block, Liaohe Oilfield, in China. Significant advantages were observed through the combination of LPS-3 (an anionic surfactant) and OAB (a betaine surfactant) in reducing interfacial tension and enhancing emulsion stability, with the optimal results achieved at the ratio of 9:1. The BRH-325 polymer was found to exhibit superior viscosity enhancement, temperature resistance, and long-term stability. Graphene nanowedges were utilized as a viscosity reducer, leading to a viscosity reduction in heavy oil of 97.43%, while stability was maintained over a two-hour period. The efficacy of the combined system was validated through core flooding experiments, resulting in a recovery efficiency improvement of up to 32.7%. It is suggested that the integration of viscosity reduction and SP flooding could serve as a promising approach for improving recovery in mature heavy oil reservoirs, supporting a transition toward environmentally sustainable, non-thermal recovery methods.

1. Introduction

In recent years, unconventional oil and gas resources have become the core pillars of domestic oil and gas development, driven by advancements in exploration, production, and research [1,2,3]. As a key component of unconventional oil and gas reservoirs, heavy oil extraction plays a crucial role in bridging the significant gap in oil demand. Against the backdrop of achieving “carbon peak and carbon neutrality”, cold recovery technology for heavy oil has emerged as a promising approach due to its economic, environmentally friendly, and efficient characteristics. Among these technologies, chemical flooding has been proven essential for enhancing the cold recovery efficiency of heavy oil. Surfactants and polymers are the most critical chemical agents in chemical flooding, as their synergistic interaction not only increases the swept volume but also significantly reduces the interfacial tension (IFT) between oil and solutions [4]. Compared to alkaline–surfactant-polymer flooding, alkaline-free surfactant–polymer (SP) systems exhibit advantages such as the reduced scaling and corrosion of wellbores, as well as relatively simpler handling of produced fluids [5].

Numerous scholars have studied the binary SP system for heavy oil recovery, with widespread consensus that its oil displacement efficiency surpasses that of either polymer flooding or surfactant flooding alone. For instance, Hocine S. et al. [6] demonstrated that introducing surfactants during secondary polymer injection increased the original oil-in-place (OOIP) recovery by approximately 23%. They concluded that the alkali-free surfactant–polymer formulation developed under reservoir conditions could serve as a valuable enhancement to polymer flooding, particularly for recovering heavy oil with viscosities exceeding 1000 mPa·s. Further findings indicated that under low-temperature and low-mineralization conditions, a simple mineralization gradient injection strategy effectively reduced surfactant adsorption. Romero-Zerón, L. et al. [7] conducted oil displacement experiments and found the supramolecular SP system exhibited favorable propagation and low adsorption characteristics in loosely consolidated sand systems. The formation of a stable and viscous displacement front was facilitated by the high structural strength of the system, resulting in a significant increase in swept volume. The synergistic effects of the surfactant and polymer are characterized by increased mobility control and reduced IFT at the oil–water interface. SP flooding could provide an average incremental recovery rate improvement of 19% compared to conventional polymer flooding. Kaili, L. et al. [8] screened an SP binary system tailored for Gudong heavy oil (350 mPacs viscosity at 50 °C) in the Shengli Oilfield, China. The IFT was observed to remain relatively stable at 80 °C and a salinity of 13,000 mg·L⁻¹. Furthermore, recovery rate was improved by 44.2% with SP binary flooding compared to water flooding. And the final recovery rate of SP flooding was 3.6% higher than polymer flooding alone.

Heavy oil is characterized by its high density and viscosity, and often contains significant impurities and waxy substances [9]. Its primary components include hydrocarbons (saturated hydrocarbons, cycloalkanes, and aromatic hydrocarbons), asphaltenes, and resins. The resins and asphaltenes exhibit high polarity, a high heteroatom content, and complex molecular structures, which are the primary contributors to the elevated viscosity of heavy oil [10]. The poor fluidity due to the high viscosity of crude oil has been considered as the main challenge in enhancing heavy oil recovery. Therefore, viscosity reducers are proposed as an effective solution to this issue.

Zhang, X. et al. [11] synthesized a novel polymeric surfactant, PAMOs, which incorporated 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and sodium alpha olefin sulfonate (AOS) into the main carbon chain of acrylamide (AM). This viscosity reducer could penetrate the asphaltene molecular layer to form a “sandwich” structure, thereby weakening the intermolecular forces between asphaltene molecules. PAMOs also established strong hydrogen bonds with asphaltenes, disrupting their supramolecular structure and converting them into lower-molecular-weight forms. The hydrophobic long-chain spatial structure further inhibited the reaggregation of asphaltene molecules, effectively reducing the viscosity of heavy oil. Si, Y. et al. [12] also synthesized a boron-containing anionic–nonionic surfactant (SYW) through esterification and sulfonation reactions. The raw materials were 1,3-propylene glycol polyether (PPG), boric acid, maleic anhydride (MA), and sodium metabisulfite. It was revealed that SYW achieved a viscosity reduction rate of 97.3%. Moreover, when SYW was combined with oleic acid and ethanolamine in a 3:1:1 ratio to produce SYG, the viscosity reduction rate could be increased to 98.6%. The emulsion containing SYG exhibited a transition in the dispersed phase from water droplets to oil droplets. The oil droplets had a uniform particle size of 3.68 μm, which enhanced fluidity.

It is widely believed that viscosity reducers are an effective enhanced oil recovery (EOR) technique in addressing the challenges of heavy oil recovery. The novel graphene nanowedge viscosity reducer was employed in this study. It was a two-dimensional nanomaterial, and formed a wedge-shaped front at the oil–water–rock interface. The structural separation pressure was generated by the formation of this interface. This pressure could detach the oil film from the rock surface, thereby allowing it to enter the mobile phase. The modified graphene nanowedge with surfactant molecules was found to exhibit large hydrophilic groups and multiple lipophilic groups. These characteristics enabled significant interaction with heavy oil. Under the shear forces induced by the flow of displacement fluids, the modified graphene nanowedges were able to fragment dispersed oil clusters into smaller droplets. These droplets subsequently entered the aqueous phase. Zwitterionic surfactants in the aqueous phase enhanced this process by forming a molecular layer on the microdroplet surfaces, which prevented readhesion to the rock surface. Then, a stable oil-in-water emulsion with low viscosity and high fluidity was formed. As a result, the mobility and recovery of heavy oil could be improved.

The Haiwaihe Block of Liaohe Oilfield in China is a multi-layer sandstone reservoir, with an oil well section of 200–400 m. The matured reservoir is primarily composed of sedimentary rocks, with significant contributions from sandstone and siltstone. These rocks are characterized by their fine to medium grain size and relatively high porosity and permeability, which are conducive to oil accumulation. Overall, the matured reservoir exhibits medium porosity and medium-high permeability, with an average porosity of 28.7% and an average permeability of 858 mD. The reservoir also exhibits strong heterogeneity. After more than 30 years of water flooding, the water cut of the reservoir is 92.8% and the recovery rate is 44.8%. The temperature of the reservoir is 60 °C. The crude oil viscosity under reservoir conditions is 100 mPa·s, and the total dissolved solids (TDSs) are 1814.3 mg/L.

Currently, the block primarily employs thermal recovery techniques for conventional heavy oil extraction, which lead to substantial carbon emissions. The balancing between thermal and non-thermal recovery techniques is essential to align with carbon reduction targets and to fulfill development goals for enhanced oil production. In this study, a viscosity reducer was utilized to lower the viscosity of heavy oil, followed by the application of an optimized SP flooding system to increase oil displacement efficiency. This approach aims to enhance oil recovery by improving the flowability of heavy oil and facilitate the transition from thermal to water flooding techniques. This research could provide a technical basis for the application of viscosity-reduced SP flooding in heavy oil reservoirs.

2. Materials and Methods

2.1. Experimental Materials and Equipment

2.1.1. Surfactant Samples

The surfactants used in this study include petroleum sulfonate, betaine, and polyether. Five types of petroleum sulfonates, including LPS-1, LPS-2, LPS-3, LPS-4, and LPS-5, were provided by RIPED (Beijing, China). Betaine OAB (oleic acid amide propyl betaine), HSB1214 (alkyl C12–14 hydroxypropyl sulfobetaine), and HSB1618 (alkyl C16–18 hydroxypropyl sulfobetaine) were provided by Shandong Yousuo Chemical Technology Co., Ltd. (Linyi, China). The polyethers HH-B1, HH-B2, and HH-B3 were provided by Changzhou Haohua Chemical Co., Ltd. (Changzhou, China).

2.1.2. Polymer Samples

Three linear Hydrolyzed Polyacrylamides—HPAMs—(M_w = 2000 × 10⁴, 2500 × 10⁴ and 3000 × 10⁴) and one high-branched HPAM (BRH-325) were employed as the polymers in this study. All of these polymers were provided by RIPED.

2.1.3. Viscosity Reducer Samples

Two types of traditional viscosity reducers, VR-SF and CA601S-HNS, were provided by Ningbo Fengcheng Advanced Energy Materials Research Institute Co., Ltd. (Ningbo, China). And a novel graphene viscosity reducer was provided by RIPED.

2.1.4. Oil Samples

The degassed and dehydrated heavy oil used in this study was sourced from the target block. The oil from the target block contained a large number of saturated hydrocarbons and aromatic hydrocarbons, with relatively low asphaltene content, and it was classified as an intermediate base oil. The water content of the heavy oil sample after dehydration was 0.8%. The density and viscosity of the crude oil were measured to be 0.965 g/cm³ and 605 mPa·s at 60 °C, respectively. The kerosene used for diluting the heavy oil was provided by RIPED.

2.1.5. Core Samples

The core samples were saturated with brine to simulate reservoir conditions, after which permeability and porosity measurements were performed in the laboratory. The properties of the cores are collected in

Table 1. Characteristics of cores.

Core	Length (cm)	Diameter (cm)	Porosity (%)	Water Permeability (mD)	Original Oil Saturation (%)
1st	9.979	2.501	33.02	1573	71.34%
2nd	9.990	2.497	33.22	1564	72.16%

.

2.1.6. Water

The water used in this study was brine, formulated to simulate the TDS of the produced water from the Haiwaihe Block. The properties of the brine are shown in

Table 2. Parameters of brine from Haiwaihe Block.

Category	pH	Ion Concentration/(mg·L−1)							TDS (mg·L−1)
		Na+	Ca2+	Mg2+	Cl−	SO42−	CO32−	HCO3−
Brine	7.86	523.77	23.36	10.73	300.18	11.95	33.18	911.13	1814.3

.

2.1.7. Experimental Equipment

The equipment utilized in this study included a Brookfield DV2T Viscometer (Brookfield Engineering, Middleborough, MA, USA) for viscosity measurements, an IFT Meter CNG-701 (CNG, Nantong, China) for interfacial tension (IFT) analysis, and a SARTORIUS BT4202S Electronic Balance (Sartorius, Göttingen, Germany) for precise weight determination. An IKA C-MAG HS 7 Magnetic Stirrer (IKA, Staufen, Germany) and an IKA EUROSTAR 20 Paddle Stirrer (IKA, Staufen, Germany) were employed for sample mixing, while a BINDER FED115 Drying Oven (BINDER, Tuttlingen, Germany) was used for sample preparation and drying. Additionally, a HAAKE MARS 60 Rotational Rheometer (Thermo Fisher Scientific, Waltham, MA, USA) was utilized to evaluate the rheological properties of the fluids.

2.2. Experimental Methods

2.2.1. Experiment for Screening Surfactant

The experimental procedures for screening surfactants under reservoir conditions were as follos: (1) Prepare individual surfactant solutions at varying concentrations (0.2%, 0.3%, 0.4%) using simulated brine. (2) Observe the dissolution behavior of surfactants at different concentrations and evaluate their solubility. (3) Measure the IFT (60 °C, 5000 revolutions per minute (rpm)) of each single surfactant solution across the prepared concentration range. (4) Identify surfactants with a high IFT reduction efficiency for further compounding. (5) Measure the IFT of the compounded surfactant solutions. (6) Use a paddle stirrer to blend the oil and compounded surfactant solution at a speed of 13,000 rpm for 30 s. (7) Observe and record the oil separation rate of the resulting emulsion to assess emulsion stability. (8) Screen the compounded surfactant solution that exhibits optimal emulsion stability and the strongest IFT reduction capability.

2.2.2. Experiment for Screening Polymer

Polymers were analyzed for key physicochemical properties, including solid content, water-insoluble content, filtration factor, and dissolution time. Additionally, the viscosity-average molecular weight of the polymers was determined under dilute solution conditions. The detailed parameters are provided in

Table 3. Physicochemical parameters of polymers.

Category	BRH-325	HPAM (2000 × 104)	HPAM (2500 × 104)	HPAM (3000 × 104)
Appearance	White Powder	White Powder	White Powder	White Powder
Solid content (%)	89.38	89.55	89.42	89.27
Dissolution rate (min)	≤120	≤120	≤120	≤120
Water-insoluble content (%)	0.088	0.116	0.104	0.140
Filtration factor	1.007	1.006	1.047	1.035
Viscosity average molecular weight (×106)	2410	2080	2600	3090

.

The polymer screening process for reservoir applicability involved the following experimental procedures: (1) Prepare polymer solutions of varying concentrations using brine. Measure the viscosities of the solutions at 60 °C using a Brookfield DV2T viscometer operated at a rotational speed of 6 rpm. (2) Evaluate the rheological behavior of two polymer solutions by measuring viscosities at varying shear rates (0.01–1000 s⁻¹) using a rotational rheometer at 60 °C, and use power-law function (1) to fit the measured rheological curve. (3) Measure the viscosities of the polymer solutions using the viscometer at different temperatures (40 °C, 45 °C, 50 °C, 55 °C, 60 °C, 65 °C, 70 °C) to assess their temperature resistance. (4) Transfer 1500 mg·L⁻¹ polymer solution into ampoules, connect them to the vacuum manifold system as shown in Figure 1, and evacuate to a pressure below 13.3 Pa for 1 h. (5) Inject nitrogen gas to restore atmospheric pressure, and seal the ampoules after repeating the process three times. (6) Place the ampoule in a drying oven set to 60 °C. At the designated aging intervals (1, 15, 30, 45, 60, 75, and 90 days), remove the ampoules, measure the viscosity, and calculate the viscosity retention rate. (7) Screen the polymer exhibiting strong viscosity-increasing properties, along with superior temperature resistance and long-term stability.

$${\eta }_v=k·{\gamma }^{n-1}$$

(1)

2.2.3. Experiment for Surfactant and Polymer Compatibility

The compatibility of polymer and surfactant is evaluated under reservoir conditions following these experimental procedures, which are in accordance with the standard (SY/T 6424-2014) of China [13]: (1) Measure the IFT of the SP compound solution using the previously described methods. (2) Measure the viscosity of the SP compound solution using the methods outlined above. (3) Compare the IFT reduction performance of the SP compound solution to that of a single surfactant. (4) Evaluate the viscosity-increasing properties of the SP compound solution against a single polymer under identical conditions.

2.2.4. Experiment for Screening Viscosity Reducer

Screening a viscosity reducer suitable for reservoir conditions is conducted through the following experimental procedures: (1) Measure the viscosity of heavy oil from the target block under 60 °C. (2) Prepare an emulsion by mixing heavy oil with a viscosity reducer solution (0.4%) at an oil-to-water ratio of 4:1. (3) Measure and record the viscosity of the emulsion at regular intervals over a 2 h period. (4) Evaluate and screen the viscosity reducer based on the observed viscosity reduction rate within 2 h.

2.2.5. Experiment for Core Flooding

Core displacement experiments are conducted to evaluate the oil displacement performance of the SP compound solution and to investigate the effect of viscosity reducers on heavy oil SP binary flooding. The core flooding experimental equipment is shown in Figure 2. The detailed experimental procedures are as follows: (1) Compound the heavy oil from the target block with kerosene in an appropriate ratio to achieve a viscosity of 100 (±5) mPa·s under 60 °C; (2) place the core in a drying oven for 12 h and weigh the core column; (3) saturate the rock core with simulated brine for 12 h, vacuum it for 12 h, and then weigh it; (4) calculate pore size and porosity; (5) according to the permeability measurement method, the permeability of the rock core is measured using simulated brine. (6) Saturate the core column with oil under 60 °C until the water cut in the measuring tube no longer increases within 3 h, and record the volume of saturated oil; (7) place the core under 60 °C for 12 h of aging. (8) Conduct water injection experiments at a rate of 0.05 mL·L⁻¹, monitor the produced water and oil volume, and calculate the water cut and the recovery efficiency at different times after the liquid flows out; (9) stop water injection when the water cut reaches 98%; (10) inject 0.3 PV viscosity reducer into the first core at a rate of 0.05 mL·L⁻¹. Follow with water injection until the water cut again reaches 98%. The second core was not injected with viscosity reducer. (11) Inject the SP compound solution into the core at a rate of 0.05 mL·L⁻¹. When the injection volume reaches 0.8 PV or more, stop injection and calculate the recovery efficiency (12). Conduct water injection experiments at a rate of 0.05 mL·L⁻¹ to monitor the water and oil production. Stop injection when the effluent no longer contains oil. (13) Evaluate the oil displacement performance of SP compound solution based on recovery efficiency, and compare the results of two core experiments to research the effect of viscosity reducer on heavy oil SP binary flooding. All experiments during the injection phase were conducted in the incubator at a temperature of 60 °C.

3. Results

3.1. Screening of Surfactants

3.1.1. Solubility of Surfactants

As shown in

Table 4. Evaluation of surfactant solubility.

Surfactants	Brine
	0.2%	0.3%	0.4%
LPS-1	White turbid liquid	White turbid liquid	White turbid liquid
LPS-2	Clear liquid	Clear liquid	Clear liquid
LPS-3	Clear liquid	Clear liquid	Clear liquid
LPS-4	Clear liquid	Clear liquid	Slight precipitate
LPS-5	Clear liquid	Clear liquid	Clear liquid
OAB	Clear liquid	Clear liquid	Clear liquid
HSB1214	Clear liquid	Clear liquid	Clear liquid
HSB1618	Clear liquid	Clear liquid	Slight precipitate
HH-B1	Clear liquid	Clear liquid	Clear liquid
HH-B2	Significant precipitate	Completely insoluble	Completely insoluble
HH-B3	Clear liquid	Clear liquid	Clear liquid

, most petroleum sulfonates demonstrated favorable solubility in the simulated brine and showed no precipitation at concentrations up to 0.3%. However, at an LPS-4 concentration of 0.4%, slight precipitation was observed, whereas other petroleum sulfonates remained completely soluble. In terms of betaine surfactants, most exhibited a clear liquid state, except for HSB1618, as it displayed slight precipitation at a concentration of 0.4%. Among polyether surfactants, HH-B2 exhibited low solubility. Significant precipitate occurred at a concentration of 0.2%. It became completely insoluble when the concentration exceeded 0.3%.

These findings offered valuable insights into the solubility behavior of various surfactants in brine and provided a basis for screening optimal surfactant formulations in EOR applications within the target reservoir. Based on the solubility test results, ten out of the eleven surfactants (excluding HH-B2) were selected for subsequent experiments.

3.1.2. Interfacial Tension Reduction of Surfactants

Previous studies had demonstrated that surfactants exhibited effective oil displacement performance when the IFT was reduced to a magnitude of 10⁻³ mN/m or lower [14,15,16]. As listed in

Table 5. IFT between oil and solution with different concentrations of surfactants.

Surfactant	Concentration (%)	IFT (mN·m−1)
LPS-1	0.2	1.09
	0.3	1.60 × 10−1
	0.4	1.17 × 10−1
LPS-2	0.2	2.11
	0.3	2.18 × 10−1
	0.4	8.08 × 10−2
LPS-3	0.2	1.26 × 10−1
	0.3	1.92 × 10−3
	0.4	5.36 × 10−4
LPS-4	0.2	5.06
	0.3	1.06
	0.4	9.83 × 10−1
LPS-5	0.2	4.39
	0.3	4.40 × 10−2
	0.4	1.15 × 10−2
OAB	0.2	5.92 × 10−3
	0.3	7.88 × 10−3
	0.4	5.91 × 10−3
HSB-1214	0.2	1.67 × 10−1
	0.3	1.04 × 10−1
	0.4	1.22 × 10−1
HSB-1618	0.2	1.23 × 10−2
	0.3	2.25 × 10−3
	0.4	2.76 × 10−3
HH-B1	0.2	1.25
	0.3	2.66
	0.4	5.44
HH-B3	0.2	1.55
	0.3	1.61
	0.4	5.44

, three surfactants including LPS-3, OAB, and HSB1618 exhibited better IFT reduction properties than the others. The anionic surfactant LPS-3 exhibited superior performance, attributed to the presence of sulfonic acid groups (-SO₃H) in its molecular structure. These functional groups impart strong hydrophilicity, significantly reducing the IFT between oil and solution and enhancing oil-washing efficiency. OAB and HSB1618, as amphoteric surfactants, demonstrated excellent surface activity and emulsification properties.

Figure 3, Figure 4 and Figure 5 illustrate that increasing the concentration from 0.3% to 0.4% resulted in minimal change in IFT across all surfactants. Notably, for LPS-3 and HSB1618, a minimum concentration of 0.3% was required to achieve IFT values at the magnitude of 10⁻³ mN/m. Based on these findings, combinations of LPS-3 with OAB and HSB1618 at a concentration of 0.3% were prepared and tested in varying ratios (9:1, 7:3, and 6:4) to investigate and optimize the synergistic effects on IFT reduction.

The experimental results for the compound solution of LPS-3 and HSB1618 were suboptimal. Among the tested ratios, the lowest IFT was 4.90 × 10⁻² mN/m at the ratio of 6:4. And none of the three ratios achieved an IFT at a magnitude of 10⁻³ at a concentration of 0.3%. The compatibility between LPS-3 and HSB1618 was poor, and experimental results indicated that the antagonistic effect weakened the ability to reduce IFT.

In contrast, a significantly higher capacity to reduce IFT was observed for the compound solution of LPS-3 and OAB compared to either surfactant alone. As shown in Figure 6, an instantaneous IFT at a magnitude of 10⁻³ was achieved by the compound solution in a shorter time than that of the individual surfactants. Additionally, the IFT was further reduced to the magnitude of 10⁻⁴ within 20 min. Furthermore, the equilibrium IFT of all three ratios remained stable at 10⁻³ for 120 min, which indicated the enhanced stability of these solutions.

The reduction in IFT through the synergistic effect of OAB and LPS-3 was demonstrated in the experiments. This phenomenon was hypothesized to result from the ability of OAB molecules to form a more compact molecular film at the oil–water interface. In contrast, when OAB was used individually, intermolecular repulsion tended to occur, potentially compromising the stability of the film. The addition of LPS-3 mitigated this repulsion through electrostatic interactions, which enhanced the compactness of the interfacial film. This improvement led to a significant reduction in IFT, as confirmed by the experimental data. Based on these results, the surfactant solution composed of LPS-3 and OAB was identified as the most effective formulation to reduce the IFT.

3.1.3. Emulsification Stability of Surfactants

Given the widely recognized importance of emulsifying ability in influencing oil displacement [17], the performance of the surfactant compound solutions was further assessed through emulsification stability experiments in this study. The time-dependent variation in oil separation rates for each emulsion is illustrated in Figure 7.

Emulsion stability was evaluated based on the oil separation rate, defined as the ratio of separated oil volume to the initial oil volume. As shown in Figure 7, OAB achieved an oil separation rate of 93.3% within the first hour, and complete oil separation occurred within one day. In comparison, LPS-3 reached 100% oil separation within the same period. The compound solutions of LPS-3 and OAB exhibited distinct emulsion stability characteristics depending on the mixing ratios. At a 6:4 ratio, the oil separation rate remained stable during the first hour. It rapidly increased and reached 100% within one day. In contrast, emulsions prepared with mixing ratios of 7:3 and 9:1 demonstrated markedly enhanced stability. Over the initial three days, the oil separation rates for the 7:3 and 9:1 were only 2.5% and 1.8%, respectively. These rates gradually increased over time and reached 45.3% and 24.7% on the 30th day.

In summary, the compound solution with an LPS-3 to OAB ratio of 9:1 exhibited the highest emulsion stability. Its oil separation rate was only 24.7% after 30 days. Among all tested solutions, emulsions prepared from compound solutions demonstrated significantly greater stability compared to those formed by individual components. This highlighted the compatibility and synergistic effects between LPS-3 and OAB in stabilizing emulsions. This increased stability was attributed to the zwitterionic structure of betaine, where the incorporation of petroleum sulfonate enhanced charge complementarity. The resulting stable charge barrier effectively suppressed aggregation at the oil–water interface and further reinforced emulsion stability.

Based on these findings, the surfactant formula was defined as a 9:1 mixture of LPS-3 and OAB. The optimal concentration of compound solution was determined to be 0.3%.

3.2. Screening of Polymer

3.2.1. Viscosity-Increasing Properties of Polymers

Viscosity measurements were conducted to assess the viscosity-increasing properties of polymers under reservoir conditions. The viscosities of polymer solutions at different concentrations are shown in Figure 8.

The HPAM (3000 × 10⁴) demonstrated the best viscosity-increasing ability, followed by BRH-325, HPAM (2500 × 10⁴), and HPAM (2000 × 10⁴). According to the permeability and porosity characteristics of examined reservoirs, both BRH-325 and HPAM (2500 × 10⁴) at a concentration of 1500 mg·L⁻¹ were identified for further experiments.

Rheological experiments were conducted to further examine the viscosity-increasing properties of these polymers under varying shear rates. The apparent viscosities of polymer solutions were compared across shear rates from 0.01 s⁻¹ to 1000 s⁻¹. As demonstrated in Figure 9, there was a decrease in apparent viscosity as the shear rate increased for both polymer solutions. It indicated pronounced shear-thinning behavior, a characteristic of pseudoplastic fluids. At high shear rates exceeding 100 s⁻¹, the apparent viscosities of both polymer solutions were comparable. In contrast, at low shear rates below 10 s⁻¹, the BRH-325 solution demonstrated a significantly higher apparent viscosity than the HPAM (2500 × 10⁴) solution. These findings highlighted the superior performance of BRH-325 under low-shear conditions, which made it a promising candidate for viscosity increasing under reservoir conditions.

Table 6. Power-law model parameters of polymer solutions at 60 °C.

Polymer	k (mPa·sn)	n	R2	Shear Rate (s−1)
BRH-325	820.98	0.243	0.9938	0.01–1000
HPAM (2500 × 104)	261.62	0.439	0.9932	0.01–1000

presents the power-law model parameters that describe the relationship between apparent viscosity and shear rate for BRH-325 and 2500 × 10⁴ HPAM solutions under 60 °C. The power-law model effectively captured the pseudoplastic behavior of both polymer solutions within the shear rate range of 0.01 to 1000 s⁻¹ (R² > 0.99). This model has been widely validated and employed to characterize the rheological properties for polymer solutions [18,19,20,21,22]. As shown in Table 6, the power-law exponent n of both solutions was less than 1, which confirmed the pseudoplastic fluid behavior. Additionally, the viscosity index k for BRH-325 was higher than that for the 2500 × 10⁴ HPAM solution, consistent with the data presented in Figure 9. These results indicate that the BRH-325 solution demonstrated a better ability to increase viscosity compared to the 2500 × 10⁴ HPAM solution.

3.2.2. Temperature Resistance of Polymers

The viscosity of polymer solutions was measured at various temperatures to construct viscosity–temperature curves and analyze viscosity variation trends. The resulting curves are shown in Figure 10. The viscosity of both polymer solutions decreased as the temperature increased, which aligned with the typical viscosity–temperature behavior of polymers. It indicated that higher temperatures accelerated polymer molecule degradation, which resulted in reduced viscosity and a weakened thickening effect. A sharp decrease in viscosity was observed under temperatures exceeding 55 °C. Additionally, the viscosity reduction was more pronounced for the HPAM (2500 × 10⁴) solution compared to BRH-325. Accordingly, BRH-325 not only exhibited superior viscosity-increasing properties at the same temperatures but also demonstrated stronger temperature resistance.

3.2.3. Long-Term Stability of Polymers

Polymer hydrolysis, particularly in polyacrylamide and its derivatives, alters charge distribution and affects viscosity enhancement. In the presence of divalent cations such as Ca²⁺ and Mg²⁺, this process may lead to precipitation. Therefore, evaluating the aging performance of polymers was essential to assess their long-term stability and effectiveness [23]. The long-term stability was evaluated by monitoring viscosity changes over a 90-day period. As shown in Figure 11, both polymers exhibited a gradual decrease in viscosity over time. A gradual and consistent decrease in the viscosity of the BRH-325 solution was observed, whereas a significant decline in the viscosity of the HPAM (2500 × 10⁴) solution was noted after 45 days. Overall, BRH-325 was found to exhibit greater long-term stability.

Figure 12 demonstrates that the viscosity retention rates of both polymers remain above the minimum standard requirement at 30 days and 90 days. Based on these findings, BRH-325 was selected for subsequent experiments at a concentration of 1500 mg·L⁻¹.

3.3. Compatibility of Surfactants and Polymer

The compatibility of the SP compound solution was evaluated through IFT and viscosity tests. The SP compound solution consisted of a 0.3% LPS-3/OAB (9:1) surfactant solution and a 1500 mg·L⁻¹ BRH-325 solution. The IFT test was conducted according to the procedures outlined previously.

As observed in Figure 13, the instantaneous IFT of the SP compound solution was 2.03 × 10⁻⁴ mN/m, significantly below the 10⁻³ mN/m threshold. The IFT remained stable at the magnitude of 10⁻³ for 120 min. Furthermore, the SP compound solution achieved the magnitude of 10⁻³ within 5 min, outperforming the surfactant solution, which required 7 min. These results indicated that the addition of polymers did not negatively impact the IFT reduction performance of the surfactant system. Instead, the polymers exhibited a synergistic effect by modifying the arrangement of surfactant molecules at the oil–water interface. This interaction reduced the critical micelle concentration (CMC) and improved micelle stability [24,25]. The time required for the IFT to reach the magnitude of 10⁻³ was shorter, resulting in reduced time costs. This improvement presented significant implications for cost reduction and enhanced efficiency in oilfield operations.

The viscosity test results for both the SP compound solution and the BRH-325 solution are shown in Figure 14. Both solutions exhibited a decrease in viscosity with increasing temperature. At lower temperatures (40–55 °C), the viscosities of the two solutions were comparable; however, a significant reduction in viscosity was observed, starting under 55 °C. Notably, the viscosity of the SP compound solution decreased less than that of the BRH-325 solution, which indicated better temperature resistance and superior viscosity-maintaining performance at elevated temperatures. These findings suggested that the incorporation of surfactants slightly improved both the viscosity and temperature resistance of the polymer. This further confirmed the compatibility of the components.

3.4. Screening of Viscosity Reducer

The performance of viscosity reducers was evaluated through viscosity reduction and stability experiments. The initial viscosity of heavy oil was measured as 605.9 mPa·s under 60 °C using a viscometer. Three viscosity reducers were separately mixed with the heavy oil, and their viscosity changes over time were recorded, as shown in Figure 15. As depicted, the viscosity of heavy oil was reduced from 605.9 mPa·s to 48 mPa·s by VR-SF, which achieved a viscosity reduction rate of 92.08%. However, the viscosity gradually increased over time, reaching 485.9 mPa·s after 2 h, with the viscosity reduction rate declining to 19.81%. The CA601S-HNS demonstrated better initial performance. The viscosity of heavy oil was reduced from 605.9 mPa·s to 28.8 mPa·s, which corresponded to a viscosity reduction rate of 95.25%. After 2 h, the viscosity increased to 389.5 mPa·s, and the viscosity reduction rate decreased to 35.71%. Both VR-SF and CA601S-HNS exhibited a significant reduction in viscosity reduction rates over time. This indicated limited stability in maintaining viscosity reduction. In contrast, superior performance was demonstrated by the graphene viscosity reducer, with the viscosity of the heavy oil reduced to a minimum of 15.6 mPa·s, which achieved a viscosity reduction rate of 97.43%. Notably, the viscosity remained stable within 1 h, and slightly rebounded to 26.6 mPa·s after 2 h. This corresponded to a viscosity reduction rate of 95.61%. The graphene viscosity reducer not only achieved the highest viscosity reduction rate but also exhibited significantly better stability compared to VR-SF and CA601S-HNS.Therefore, the graphene viscosity reducer was proposed as an effective solution for reducing heavy oil viscosity.

3.5. Core Flooding Experiments

This study evaluated the effectiveness of the SP compound solution in core displacement experiments by recording produced fluid and pressure changes. The core sample parameters are listed in Table 1, while Figure 16 and Figure 17 illustrate the variations in recovery efficiency, water cut, and pressure with injection volume for both cores.

As shown in Figure 16, during the initial water flooding, the pressure increased to 0.25 MPa. After injecting 0.12 PV, the water cut began to rise rapidly. By 0.88 PV, the water cut reached 98%, the pressure was 0.26 MPa, and the cumulative recovery efficiency was 43.4%. Subsequently, 0.3 PV of a graphene viscosity reducer was injected. This led to an increase in pressure to 0.45 MPa and a decrease in the water cut to 83%, accompanied by significant emulsification in the produced liquid. This indicated the formation of a low-viscosity oil-in-water emulsion at the displacement front, enhancing displacement efficiency by mobilizing high-viscosity crude oil. Following this phase, continued water injection raised the recovery efficiency to 50.1%, an improvement of 6.7%. Next, SP compound solution was injected. The displacement pressure rose, and the water cut decreased to a minimum of 40% at 0.3 PV injection, before increasing again. By the end of SP flooding, the water cut reached 90%, and the recovery efficiency was 80.9%. After subsequent water injection, recovery efficiency further increased to 82.8%, representing a 32.7% improvement due to SP flooding and subsequent water injection.

As shown in Figure 17, The initial water injection pressure for the 2nd core was 0.35 MPa. After injecting 0.29 PV, the water cut increased rapidly. At 1.1 PV injection, water flooding stopped with a water cut of 100%, pressure of 0.35 MPa, and a cumulative recovery efficiency of 38.8%. Injecting the SP compound solution raised displacement pressure and reduced water cut. The water cut reached a minimum of 73.3% at 0.44 PV injection before rising again. By the end of SP flooding (0.8 PV), the water cut reached 90%, and the recovery efficiency was 60.2%. Subsequent water flooding increased recovery efficiency to 61.2%, resulting in an overall enhancement of 22.4% due to SP flooding and water injection.

The experimental results showed that SP flooding could significantly enhance recovery efficiency on the basis of water flooding. The injection of the SP compound solution improved the viscosity of the displacement phase and expanded the swept volume. It also started the residual oil at the blind end, increased the number of capillaries, reduced the IFT, and stripped the heavy oil attached to the rock surface. These effects further improved the oil displacement efficiency. The addition of viscosity reducers could effectively improve the fluidity of heavy oil and reduce its viscosity. It proved that mobility control contributed greatly to the recovery efficiency [26,27,28,29,30]. The injection of graphene viscosity reducer effectively reduced the viscosity of heavy oil and increased the mobility of the displaced phase. However, the dynamic viscosity-increasing effect of the SP slug raised the viscosity of the displacement phase. It also increased the flow resistance, improved the resistance coefficient, and reduced the mobility of the displacement phase. When the mobility ratio was lower than 1, the affected volume increased and the recovery efficiency could be significantly increased.

4. Conclusions

This study investigated the potential of SP systems for enhanced oil recovery in heavy oil reservoirs, focusing on the Haiwaihe Block in Liaohe Oilfield. Key findings include the following:

(1)

(LPS-3/OAB (9:1) demonstrated the best ability to reduce interfacial tension, achieving an IFT reduction of 10⁻⁴ mN/m and maintaining equilibrium at 10⁻³ mN/m. The system exhibited excellent emulsification stability, with an oil separation rate of only 24.7% after 30 days.

(2)

BRH-325 showed stronger viscosity enhancement, temperature resistance, and long-term stability compared to HPAM (2500 × 10⁴), with a viscosity retention rate of 94.1% after 90 days under 60 °C.

(3)

The graphene viscosity reducer achieved a maximum viscosity reduction rate of 97.43% and maintained a 95.61% reduction after 2 h, outperforming other reducers.

(4)

In the 1st Core, PS flooding increased oil recovery by 32.7%, reaching a total efficiency of 82.8%. In the 2nd Core, SP flooding increased oil recovery by 22.4%, achieving a final efficiency of 61.2%.

The SP system synergistically reduced IFT, improved emulsion stability, increased the viscosity of the displacement phase, and enhanced mobility control. These effects collectively expanded the swept volume, stripped residual oil, and significantly improved recovery efficiency. This research provides a practical basis for advancing chemical EOR technologies in heavy oil reservoirs.