New Evaluation System for Extra-Heavy Oil Viscosity Reducer Effectiveness: From 1D Static Viscosity Reduction to 3D SAGD Chemical–Thermal Synergy

Abstract

To overcome the production bottleneck induced by the high viscosity of extra-heavy oil and resolve the issues of limited efficiency in traditional thermal oil recovery methods (including cyclic steam stimulation (CSS), steam flooding, and steam-assisted gravity drainage (SAGD)) as well as the fragmentation of existing viscosity reducer evaluation systems, this study establishes a multi-dimensional evaluation system for the effectiveness of viscosity reducers, with stage-averaged remaining oil saturation as the core benchmarks. A “1D static → 2D dynamic → 3D synergistic” progressive sequential experimental design was adopted. In the 1D static experiments, multi-gradient concentration tests were conducted to analyze the variation law of the viscosity reduction rate of viscosity reducers, thereby screening out the optimal adapted concentration for subsequent experiments. For the 2D dynamic experiments, sand-packed tubes were used as the experimental carrier to compare the oil recovery efficiencies of ultimate steam flooding, viscosity reducer flooding with different concentrations, and the composite process of “steam flooding → viscosity reducer flooding → secondary steam flooding”, which clarified the functional value of viscosity reducers in dynamic displacement. In the 3D synergistic experiments, slab cores were employed to simulate the SAGD development process after multiple rounds of cyclic steam stimulation, aiming to explore the regulatory effect of viscosity reducers on residual oil distribution and oil recovery factor. This novel evaluation system clearly elaborates the synergistic mechanism of viscosity reducers, i.e., “chemical empowerment (emulsification and viscosity reduction, wettability alteration) + thermal amplification (steam carrying and displacement, steam chamber expansion)”. It fills the gap in the existing evaluation chain, which previously lacked a connection from static performance to dynamic displacement and further to multi-process synergistic adaptation. Moreover, it provides quantifiable and implementable evaluation criteria for steam–chemical composite flooding of extra-heavy oil, effectively releasing the efficiency-enhancing potential of viscosity reducers. This study holds critical supporting significance for promoting the efficient and economical development of extra-heavy oil resources.

1. Introduction

With the continuous growth of global energy demand and the gradual depletion of conventional crude oil recoverable reserves, the stability and sustainability of the energy supply has become a core issue of global concern. As an unconventional energy resource with abundant reserves, extra-heavy oil accounts for a significant proportion of the world’s total oil and gas geological reserves, which is widely distributed in countries including Canada, the United States, Venezuela, China, Indonesia, and Russia [1] and holds an irreplaceable strategic position in alleviating the imbalance between energy supply and demand [2,3,4,5]. Faced with the growing shortage of conventional oil, the efficient development of unconventional oilfields has become a key direction for safeguarding energy security. Among these unconventional oil resources, heavy oil exhibits substantial potential. As a critical component of global energy reserves [6], extra-heavy oil poses severe technical challenges to exploitation, primarily due to its inherent high viscosity and poor fluidity.

Traditional thermal oil recovery technologies commonly face bottlenecks in the development of extra-heavy oil. The mainstream technology, steam huff and puff, is prone to problems such as a sharp decline in single-well production and the oil–steam ratio approaching the economic threshold in the later stages. Steam flooding is restricted by the high viscosity of crude oil and reservoir heterogeneity, resulting in low sweep efficiency and residual oil in low-permeability zones is difficult to effectively mobilize. While Steam-Assisted Gravity Drainage (SAGD) technology has the potential for efficient recovery, it has strict requirements on conditions such as reservoir thickness and permeability and also has issues including limited oil displacement efficiency and high water consumption [7,8,9,10]. These bottlenecks have seriously restricted the efficient mobilization of extra-heavy oil resources, and there is an urgent need to break through the predicament through the coupled technology of chemical viscosity reduction and thermal oil recovery, so as to realize the synergistic enhancement of development efficiency and economy [11,12].

Viscosity reduction technologies for heavy oil mainly include physical heating, light oil dilution, addition of chemical viscosity reducers, and application of hydrothermal cracking catalysts [13,14]. Among these, physical heating methods are characterized by high energy consumption and excessive costs; light oil dilution methods are limited by the shortage of light oil resources; and oil-soluble chemical viscosity reducers and hydrothermal cracking catalysts have the drawbacks of high selectivity and poor field adaptability. In contrast, water-soluble chemical viscosity reducers have become the core technical direction for viscosity reduction in extra-heavy oil at present, owing to their advantages of a significant viscosity-reduction effect, simple process of operation, and high cost-effectiveness [15]. The mainstream type of water-soluble viscosity reducers, surfactants can replace the active substances in heavy oil by adsorbing at the oil–water interface, promoting the formation of oil-in-water (O/W) emulsions from crude oil, thereby reducing the viscosity of the system [16]. However, existing surfactant-based viscosity reducers still have shortcomings: their small molecular structure results in low acting efficiency, weak affinity with heavy oil, and poor stability of the formed O/W emulsions, and some high-performance surfactants have high raw material costs and complex preparation processes, making it difficult to meet the economic requirements of large-scale industrial applications [17].

An ideal viscosity reducer should possess high surface and interfacial activity, strong emulsifying capacity, and good viscoelasticity. It can interact sufficiently with extra-heavy oil to form stable oil-in-water (O/W) emulsions, which not only significantly reduces crude oil viscosity but also improves oil–water interfacial properties [18]. Furthermore, it can form a “chemical–thermal” synergistic effect with steam [19], providing a key technical approach for enhancing the efficiency of thermal oil recovery. However, the current application of viscosity reducers still faces core challenges. Existing evaluation systems are primarily focused on static viscosity reduction effects (e.g., determination of viscosity reduction rate), lacking systematic research on the screening of optimal concentrations and optimization of slug parameters during dynamic displacement processes. There is insufficient quantitative analysis of the synergistic mechanism between viscosity reducers and thermal processes such as steam flooding and SAGD, making it difficult to accurately describe the action law of “thermal–chemical” coupling. The evaluation indicators are single, and a full-process evaluation framework—from static performance testing to dynamic displacement verification, and further to multi-process synergy adaptation—has not been established. This leads to blindness in on-site applications and makes it difficult to fully unlock the efficiency-increasing potential of viscosity reducers [15].

Scholars at home and abroad have conducted extensive research in the field of composite development of extra-heavy oil [20,21], laying a solid foundation for subsequent studies. Some studies have identified that converting to flooding after the later stage of steam huff and puff is a key direction for enhancing oil recovery, and systematically analyzed the reservoir adaptability of mainstream flooding conversion modes such as steam flooding and chemical flooding, providing a theoretical basis for the transition of development stages [22]. Other studies have focused on optimizing parameters (e.g., injection pressure, slug size) for chemical agent composite flooding, offering references for the on-site regulation of process parameters [23]. Since the proposal of SAGD technology in 1981 [24], pilot experiments have been gradually carried out in related fields, and chemical auxiliary technologies have been introduced to develop composite development modes, further expanding its application scenarios [25]. In addition, some studies have revealed the regulatory effect of viscosity reducers on heavy oil viscosity and the basic synergistic mechanism between viscosity reducers and steam through static viscosity reduction evaluation and dynamic sand-packed tube displacement experiments, providing data support for the initial establishment of “viscosity reduction–steam composite flooding” schemes. Despite the fact that these studies have promoted technological development, they still fail to address the core issues, including the fragmentation of evaluation systems, insufficient quantification of synergistic effects, and unclear concentration–process matching relationships.

Focusing on extra-heavy oil as the research object, this study innovatively establishes a multi-dimensional evaluation system for the effectiveness of viscosity reducers, with stage-averaged remaining oil saturation as the core benchmark. Different from the isolated experimental designs in existing studies, this study achieves a systematic upgrade of evaluation dimensions through a “1D static–2D dynamic–3D synergistic” progressive experimental framework. In the 1D static experiments, gradient concentration tests are conducted to establish the quantitative relationship between viscosity reduction rate and concentration, identify the optimal concentration, and establish a benchmark for subsequent experiments. In the 2D dynamic experiments, comparisons among multiple displacement schemes are performed to quantify the oil displacement efficiency of the viscosity reducer at the optimal concentration under dynamic conditions. The 3D synergistic experiments, on the other hand, simulate the SAGD development scenario after cyclic steam stimulation (CSS), reveal the efficiency-enhancing mechanism of viscosity reducers in reducing stage-residual oil saturation and improving the oil recovery factor, and thus form a full-chain evaluation logic covering “basic performance–dynamic adaptation–process synergy”. This progressive design not only makes the evaluation results more consistent with field practices, but also for the first time integrates the core indicator of stage-averaged remaining oil saturation into multi-dimensional experiments, realizing a breakthrough in viscosity reducer effectiveness evaluation from “qualitative description” to “quantitative measurement” and from “single-link assessment” to “full-process coverage”. Meanwhile, through this system, the essence of viscosity reducers achieving efficiency enhancement via “chemical empowerment + thermal amplification” is systematically clarified. This provides quantifiable and implementable evaluation criteria and technical support for steam–chemical composite flooding of extra-heavy oil, and holds significant importance for promoting the efficient and economical development of extra-heavy oil resources, as well as facilitating technological upgrading, cost reduction, and efficiency improvement in the energy exploitation field.

2. Static Evaluation of Viscosity Reduction Effect

2.1. Experimental Design

The concentration of the viscosity reducer was set to 10 gradients, with each gradient increasing by 0.2 percentage points (ranging from 0.2% to 2.0%). After the viscosity reducer at each concentration was fully mixed with crude oil, the viscosity was measured, and the viscosity reduction rate curve was plotted (as shown in Formula (1)).

$$f={\displaystyle \frac{{\mu }_0-\mu }{{\mu }_0}}\times 100\%$$

(1)

where μ: Viscosity of the heavy oil emulsion after adding the viscosity reducer sample, mPa·s; μ₀: Original viscosity of the heavy oil (viscosity at a viscosity-reducer concentration of 0%), mPa·s; f: Viscosity reduction rate, %; where a higher viscosity-reduction rate indicates a more significant viscosity-reduction effect.

2.2. Experimental Procedures

NaHCO₃ formation water with a salinity of 2100 mg/L was prepared (this solution exhibits excellent chemical stability), and viscosity reducers were added at a concentration gradient of 0.2–2.0% for storage (hereafter referred to as viscosity reducer solutions). Crude oil was dehydrated, and its water content was measured; once the water content was <2%, the crude oil was transferred to a constant temperature oven at 150 °C ± 1 °C for preheating. Simultaneously, a falling-ball viscometer was calibrated: suitable stainless-steel balls were selected and preheated to 150 °C, after which crude oil without added viscosity reducer was injected into the viscometer to determine its viscosity. The viscometer was cleaned with petroleum ether after the measurement. Heavy oil and the viscosity reducer were mixed at a mass ratio of 7:3 (To achieve the target oil-dominant (oil-rich and water-lean) water-in-oil (W/O) emulsion, and considering the operating conditions of viscosity testing (temperature set at 150 °C), and that partial liquid phases (especially the aqueous phase) are prone to vaporization at this temperature. This vaporization may damage the interfacial stability of the emulsion and cause demulsification. Therefore, from the perspective of system stability control, the oil phase-to-aqueous phase mass ratio was set to 7:3 to suppress the impact of high-temperature vaporization on the emulsion structure. Meanwhile, a two-step treatment of “stirring dispersion–standing verification” was adopted. The stirring stage ensures sufficient mixing of the oil and aqueous phases to form a homogeneous dispersed system, while the standing stage further verifies the emulsion’s stability without external disturbance. This avoids compromising the accuracy of test data due to stratification or demulsification during subsequent testing. The emulsion was stirred at 1400 r/min for 15 min and then allowed to stand for 15 min until no free water precipitated, thus preparing a stable emulsion (in compliance with the national standard GB/T 8929) [26]. Pretreated emulsions of each concentration were taken sequentially, stirred at 800 r/min for 2 min under a constant temperature of 150 °C, and then injected into the falling-ball viscometer to measure their viscosity. The viscosity reduction rate was calculated, and the accuracy of the viscosity reduction effect determination was improved through gradient-based precise operations (the falling-ball viscometer is shown in Figure 1).

2.3. Dynamic Solution of Gas–Oil Ratio

At the initial stage of static evaluation, a viscometer was used to measure the viscosity of crude oil (with a water cut <2%) at 150 °C, which was determined to be 8930 mPa·s. A temperature of 150 °C exhibits a strong effect on improving the rheological properties of heavy oil: a further increase in temperature would lead to unnecessary economic losses, whereas when the temperature is lower than 150 °C, the slowed thermal motion of molecules results in reduced adsorption efficiency. Additionally, the relatively high viscosity of crude oil and the enhanced interaction between asphaltenes and resins lead to insufficient emulsification and viscosity reduction. As the viscosity reducer was added and its concentration gradually increased from 0.2% to 2.0%, the viscosity of the crude oil showed a significant decreasing trend. When the concentration increased from 0.2% to 0.8%, the viscosity reduction rate jumped from 41.4% to 95.7% (as shown in the curve of Figure 2), with a significant increase in the absolute value of the trend slope. At this stage, the viscosity reducer molecules began to interact with macromolecules such as asphaltenes and resins in the crude oil, breaking the hydrogen bonds and van der Waals forces between them, thereby reducing the viscosity of the crude oil. At low concentrations, the effective active sites were unsaturated, so the increase in concentration was directly converted into an improvement in viscosity-reduction efficiency, showing a linear positive upward trend. When the concentration exceeded 1.0%, the slope of the viscosity reduction rate approached zero (maintained at 97% ± 1.0%), and the curve extended approximately horizontally. At this point, the viscosity reducer molecules formed a critical micelle concentration (CMC) in the crude oil [27]. These molecules self-assembled into micelles through hydrophobic interactions, encapsulating heavy components such as asphaltenes in the micelle core to form a stable dispersion system. At this stage, the adsorption at the oil–water interface reached saturation, and the excess viscosity reducer molecules no longer participated in effective interactions.

When the concentration of the viscosity reducer is low, it disrupts asphaltene aggregates through molecular dispersion; when the concentration is high, it stabilizes the dispersion system via micellization. In actual construction, the concentration should be controlled at 0.8% (with the emulsion viscosity being 400 mPa·s). This is because a relatively low concentration of the chemical can balance viscosity reduction efficiency and economy, avoiding increased costs and pollution caused by “concentration redundancy” when the concentration exceeds the critical value. Therefore, in the subsequent dynamic displacement evaluation, solutions with viscosity reducer concentrations of 0% and 0.8% were selected for comparison.

3. Evaluation of the Effect of Viscosity Reducer Concentration on Steam–Chemical Composite Flooding

3.1. Experimental Design

The 0.8% concentration viscosity reducer was optimized and selected via static viscosity reduction evaluation, which was then applied in the two-dimensional sand-packed tube experiment. In this stage, two displacement schemes were designed for comparison: ultimate steam flooding (i.e., single steam flooding, intended to characterize the ultimate oil-recovery efficiency and remaining oil characteristics), and switching to 0.8% viscosity reducer flooding after steam flooding (aimed at enhancing remaining oil production). Comparative analysis can delineate the ultimate capacity of steam flooding and the remaining oil distribution, evaluate the performance of the viscosity reducer, provide data support for steam–chemical composite flooding, and demonstrate the oil recovery efficiency of steam flooding as well as the oil increment effect of composite flooding. First, the experiment explores the oil increment effect under the ultimate state; subsequently, the slug size is optimized by adjusting the injection volume.

3.2. Sand-Packed Tube Process

During the preparation of sand-packed tubes, 40–70 mesh quartz sand and natural core powders were selected and mixed at a mass ratio of 9:1. A high-precision balance (with an accuracy of 0.01 g) was used to weigh the quartz sand and natural core powder separately; this ratio was designed to reproduce the physicochemical properties of real formations, balance the authenticity, controllability, and economy of the experiment, and provide reliable data support for field operations. The two materials were then placed in a clean container and stirred thoroughly to ensure uniform mixing, yielding the filler required for the experiment. The prepared filler was slowly packed into the sand-packed tube; during the packing process, the tube wall was tapped lightly continuously to make the filler uniform and dense, thus preventing the formation of gaps or stratification (The sand-packed tube mold is shown in Figure 3, and the core data of the sand-packed tube are presented in

Table 1. Basic data of sand-packed tube cores.

Sand-Packed Tube Number	Sand-Packed Tube Size (cm)	Permeability (mD)	Porosity (%)
1-1	30 × 2.5	2622	38.7
1-2		2599	38.4
2-1		2598	38.04
2-2		2610	39.06
3-1		2660	39.4
3-2		2689	43.48
4-1		2510	39.07
4-2		2577	40.42

).

3.3. Evaluation of Oil Increment Effect of Viscosity Reducer After Ultimate Steam Flooding

3.3.1. Experimental Process and Its Schematic Diagram

After measuring the dimensions of the sand-packed tube, its permeability was measured using nitrogen gas. Subsequently, the tube was vacuumed and then saturated with water, followed by the determination of water saturation and porosity via the dry–wet weight method. The sand-packed tube was preheated in a thermostat at 150 °C (with stabilization for ≥30 min) and then connected to a pressure monitoring device and displacement equipment. Simulated oil with a viscosity of 8930 mPa·s (at 150 °C) was injected at a rate of 0.5 mL/min until the oil saturation exceeded 75%. After the steam generator stabilized at 150 °C, steam was injected at the same rate for displacement, and pressure and oil recovery data were recorded in real time. Among the sand-packed tubes, displacement for Tube 1–1 was terminated when the water cut reached ≥98%. For Tube 1–2, after the completion of steam flooding, a viscosity reducer with a concentration of 0.8% (verified as the optimal concentration under the same conditions in the static optimization experiment) was continuously injected until the same water cut was achieved. After the experiment, the data were organized, and the process is shown in Figure 4 (The core samples corresponding to the experimental projects are shown in

Table 2. Experimental project of sand-packed tube core.

Sand-Packed Tube Number	Experimental Scheme	Permeability Error (mD)	Porosity Error (%)
1-1	Ultimate Steam Flooding	2610.5 ± 16.2	38.55 ± 0.21
1-2	Ultimate Steam Flooding
2-1	After steam flooding to 15% oil recovery factor, switch to 0.2% concentration viscosity reducer flooding until the limit.	2604.0 ± 8.5	38.75 ± 0.72
2-2	After steam flooding to 15% oil recovery factor, switch to 0.2% concentration viscosity reducer flooding until the limit.
3-1	After steam flooding to 15% oil recovery factor, switch to 0.8% concentration viscosity reducer flooding until the limit.	2674.5 ± 20.5	41.44 ± 2.04
3-2	After steam flooding to 15% oil recovery factor, switch to 0.8% concentration viscosity reducer flooding until the limit.
4-1	After steam flooding to 15% recovery factor, switch to 0.8% concentration viscosity reducer flooding for 3 pore volumes (PV), then switch back to steam flooding to ultimate state.	2543.5 ± 33.5	39.75 ± 0.68
4-2	After steam flooding to 15% recovery factor, switch to 0.8% concentration viscosity reducer flooding for 3 pore volumes (PV), then switch back to steam flooding to ultimate state.

).

3.3.2. Experimental Repeatability and Variance Analysis

To ensure the reliability and statistical significance of experimental data, all tests in this study were designed with parallel repetitions, and variance was quantified using standard deviation (SD) and coefficient of variation (CV, CV = SD/mean × 100%). Specific designs and results are as follows:

2D sand-packed tube experiment: Each displacement scheme (Table 2) was repeated 2 times (n = 2). The CV of oil recovery factor and residual oil saturation was <2% (e.g., 34.4% ± 0.6% for ultimate steam flooding, and 44.5% ± 1.1% for 0.8% viscosity reducer flooding), verifying the stability of core packing and displacement operations.

3D slab core experiment: Two parallel tests were conducted for both “steam huff and puff + SAGD” and “steam huff and puff + chemical flooding + SAGD” processes (n = 2). The CV of stage residual oil saturation was <4% (e.g., 46.3% ± 1.5% for pure steam group, 38.2% ± 1.2% for chemical-aided group), confirming the reproducibility of SAGD steam chamber expansion and residual oil mobilization.

All CV values were <5%, which meets the statistical requirements for heavy-oil displacement experiments, indicating controllable operational errors and reliable experimental conclusions.

3.3.3. Experimental Results

Core 1–1 was subjected to ultimate steam flooding, achieving a final oil recovery factor of 34.4%. For Core 1–2, after the completion of ultimate steam flooding, a viscosity reducer with a concentration of 0.8% was injected to enhance oil displacement efficiency through a dual-action mechanism. However, as shown in the curve of Figure 5, after injecting 1.5 pore volumes (PV) of steam, none of the remaining 64% of the crude oil could be mobilized even with viscosity reducer flooding; within the steam-swept zone, “strongly trapped residual oil” still remained, and its flow resistance is far beyond the capacity of the viscosity reducer to overcome. Subsequent experiments further explored the optimization scheme of two-dimensional (2D) combined steam–chemical flooding.

3.4. Effects of Flooding Switching Timing and Concentration on Steam–Chemical Hybrid Flooding

3.4.1. Experimental Procedure

Measure the dimensions of the sand-packed tube and determine its permeability and porosity (via dry–wet weight method). After preheating in a 150 °C oven until internal temperature is stabilized for ≥30 min, connect it to the displacement equipment and inject simulated oil at 0.5 mL/min to achieve oil saturation under irreducible water; set it aside when oil saturation >75%. Adjust the steam generator to 150 °C and stabilize it, then inject steam for displacement at 0.5 mL/min, recording pressure and oil recovery data in real time. Stop steam injection when cumulative oil recovery reaches 15%. Switch the valve to sequentially inject 0.2% and 0.8% concentration viscosity reducers (0.5 mL/min, 3-PV slug; due to the high porosity (38–43%) of the sand-packed tube, a 3-PV viscosity reducer slug is required to prevent agent dilution in large pore spaces and ensure the concentration is maintained at the optimal level of 0.8%). Conduct a 30 min soaking period and record phase data. Preheat the steam generator to 150 °C again and continuously inject steam at 0.5 mL/min. Terminate the experiment when the water cut of produced fluid is ≥98% and stable, followed by data collation for the entire process.

3.4.2. The Comparative Analysis of Oil Recovery Degree

In this stage of the experiment, four sets of tests were conducted (with two repetitions per set; the oil recovery results are presented in Figure 6). The focus was on the heavy-oil displacement process of “steam flooding–chemical flooding–secondary steam flooding”, aiming to explore the regulatory mechanism of viscosity reducer concentration and displacement sequence on the oil recovery factor. For the first and second sets, ultimate steam flooding was implemented, relying on the thermal effect of steam to reduce crude oil viscosity, while condensed water formed a “hot water flooding” effect. However, restricted by steam sweep efficiency, the relatively high-permeability zones were mobilized first, leaving residual oil trapped in the relatively low-permeability zones. As a result, the oil recovery factor entered a bottleneck period, stabilizing between 34.4% and 35.3%. For the third and fourth sets, when the oil recovery factor of steam flooding reached 15%, the displacement was switched to a 0.2% concentration viscosity reducer. Since this concentration did not reach the effective emulsification concentration, the crude oil viscosity reduction effect was limited, making it difficult to displace the residual oil through steam flooding—especially the high-viscosity residual oil in the relatively low-permeability zones. The displacement effect was poor, with the oil recovery factor only reaching 16.5%. In the fifth and sixth sets of experiments, the viscosity reducer with an optimal concentration of 0.8% (determined in static evaluation) was used for displacement. This concentration reached the critical emulsification concentration, which could effectively emulsify and reduce viscosity, improve wettability, and displace the residual oil in the relatively low-permeability zones and pore corners that were not swept by steam flooding. This broke through the thermal flooding bottleneck, increasing the oil recovery factor to 44.5%—an increase of 9.5% compared with ultimate steam flooding and 28% compared with displacement using the 0.2% concentration viscosity reducer. For the seventh and eighth sets, a combined process of “steam flooding (to 15% recovery factor) → 0.8% viscosity reducer flooding → secondary steam flooding” was adopted. By virtue of the phased synergistic effect of “thermal viscosity reduction → chemical viscosity reduction → re-thermal viscosity reduction”, the process gradually mobilized the easily recoverable oil in high-permeability zones, the hard-to-recover oil in low-permeability zones, and the retained oil after viscosity reduction. The total oil recovery factor reached 47% to 49%. The core mechanism lies in that the high-concentration viscosity reducer breaks through the emulsification threshold and collaborates with thermal recovery technology to expand the sweep range, providing a technical pathway for ultra-ultimate recovery of heavy oil. The consistency of duplicate experimental data verifies the universality of the conclusion [28]. Meanwhile, the comparison of parallel experiments in this stage showed relatively stable results, which confirms that the viscosity reducer exhibits excellent stability at 150 °C. Furthermore, setting the injection rate to 0.5 mL/min exhibits clear suitability. It not only meets national standard requirements—ensuring sufficient contact between the agent and crude oil, enabling penetration into low-permeability zones and pore corners, and preventing uneven agent distribution—but also aligns with the subsequent steam flooding rate for three-dimensional (3D) flat cores, thereby providing a stable flow field for the composite process. An excessively high rate would shorten the agent’s action time, while an excessively low rate tends to induce “viscous fingering” in high-permeability reservoirs and disrupt displacement uniformity.

3.4.3. Comparison of Stage-Specific Residual Oil Saturation Reduction Magnitude

Average residual oil saturation is a core indicator for evaluating oil recovery factor; the magnitude of its reduction directly reflects the ability of a displacement system to mobilize remaining oil and is crucial to the production enhancement potential of heavy oil reservoirs. As can be seen from the bar chart in Figure 7, for single steam flooding (primary steam flooding) with reductions of 26.8% and 28.1%, crude oil is displaced relying on the mechanisms of thermal viscosity reduction and distillation extraction. However, constrained by steam overriding and fingering, the sweep range is limited, leading to residual oil being trapped in low-permeability zones or adhering to rock surfaces. In displacement with low-concentration (0.2%) viscosity reducer (steam + 0.2% chemical agent), only a reduction of 2.4% and 2.8% was achieved during the chemical flooding stage. Due to insufficient concentration, it was difficult to adequately reduce crude oil viscosity or alter rock wettability, resulting in weak capability to “strip and carry” residual oil. In contrast, the high-concentration (0.8%) viscosity reducer exhibited a significant synergistic effect: in the “steam + 0.8% chemical agent” displacement, the reduction during the chemical flooding stage soared to 22.5% and 22%. The underlying mechanism is that high-concentration molecules are fully dispersed, enabling strong viscosity reduction (even emulsification of crude oil), wettability alteration (from oil-wet to water-wet, stripping residual oil from particle surfaces), and expanded sweep in low-permeability zones [29], thus breaking through the bottleneck of single steam flooding. More importantly, in the “steam + 0.8% chemical agent + steam” combined displacement, a further reduction of 13.5% and 13.8% was still achieved when switching to secondary steam flooding after chemical flooding. The chemical flooding had already reshaped the fluid properties of the reservoir (viscosity reduction and emulsification), and the subsequent steam thermal recovery further enhanced heat transfer, forming a synergistic effect of “chemical viscosity reduction + thermal carrying and displacement” to deeply mobilize residual oil. In summary, the 0.8% concentration viscosity reducer breaks through the barrier of residual oil trapping via “chemical empowerment”; when combined with the thermal amplification of secondary steam flooding, it verifies the key role of “high-concentration chemical agent + combined flooding” in reducing the staged residual oil saturation of heavy oil reservoirs, thereby establishing an efficient technical pathway for improving oil recovery factor. The trend shown in the bar chart of Figure 7 is highly consistent with that in Figure 6, which confirms the reliability of the experiment and the effectiveness of the viscosity reducer in this stage of the experiment.

4. Evaluation of Displacement Effect in Late Stage of Huff and Puff

4.1. Experimental Scheme

The steam huff and puff process is cycled through three stages: injection → soaking → production. In this experiment, edge vertical wells were used for eight cycles of steam huff and puff (0.1 pore volume (PV) per cycle). After that, steam flooding was conducted, adopting the mode of injection through one vertical well and simultaneous production through vertical wells and horizontal wells. In the experiment, the concentrations of the viscosity reducer were set to 0% and 0.8%, respectively, and the combined process of steam huff and puff + steam flooding was carried out simultaneously for both concentration conditions. The experimental temperature was set to 150 °C to simulate the formation temperature; other experimental parameters were as follows: formation water salinity of 2100 mg/L, water type of NaHCO₃, displacement rate of 5 mL/min, confining pressure of 10 MPa, and simulated oil viscosity of 8930 mPa·s (at 150 °C).

4.2. Experimental Steps and Schematic Diagrams of Core and Process

After core pretreatment (including dimension measurement and porosity determination via the vacuum water saturation method; data from artificial flat cores are presented in Table 2 and

Table 3. Experimental cores and their corresponding experimental schemes.

Core Number	Core Dimensions (cm)	Permeability (mD)	Porosity (%)	Experimental Items
A-1	30 × 30 × 9	2000	23	Steam Huff and Puff + SAGD
A-2			24	Steam Huff and Puff + Viscosity Reducer Flooding + SAGD

), variable-sequence displacement in a high-pressure chamber was conducted—this involved constant-rate oil injection at 5 mL/min, with monitoring continued until the water cut reached ≥75%. Subsequently, steam huff and puff at 150 °C was implemented, following the subsequent parameters: 0.1 pore volume (PV) per cycle, 30 min of well soaking followed by 10 min of oil production, for a total of eight cycles. After adjusting the well pattern, the first stage of the experiment was completed. The well pattern was then switched to a combined configuration of two vertical wells and one horizontal well, and Steam-Assisted Gravity Drainage (SAGD) [30] was initiated: slugs with a volume of 0.5 PV (at concentrations of 0% and 0.8%, respectively) were injected, and constant-rate displacement was performed at 5 mL/min until the chemical agent was fully injected. Thereafter, steam flooding at 150 °C was resumed (injection rate: 5 mL/min) and continued until the water cut reached ≥98%. During the entire process, experimental data were recorded simultaneously (the process flow is illustrated in Figure 8, and the data from the artificial slab cores used in the experiment are presented in Table 3).

For the “primary huff and puff” and “secondary huff and puff” mentioned below, the definitions are as follows: the primary huff and puff uses the vertical well on the left side of the core diagram as the operating well, while the secondary huff and puff uses the vertical well on the right side as the operating well (as shown in the core processing diagram in Figure 9); for the convenience of distinction, the above expressions will be uniformly adopted in the following text. In the experiment, single-well operation was adopted instead of multi-well simultaneous operation, and the reasons are as follows: Firstly, single-well operation can avoid the interference caused by the superposition of pressure fields and concentration fields in multi-well systems. For multi-well arrangements in small-scale cores, the excessively small well spacing is prone to channeling, which leads to experimental distortion. Secondly, single-well operation simplifies variables, making the “parameter–effect” relationship clear and easy to analyze; in contrast, multi-well systems are faced with the problem of variable coupling, which easily results in the difficulty of disassembling the “multiple causes leading to one result” phenomenon. Thirdly, single-well operation has high controllability and good repeatability, while in multi-well operation it is difficult to ensure result reproducibility due to minor deviations in wellbore positioning and sealing. Furthermore, this operation mode conforms to the rule of laboratory experiments, i.e., “clarifying fundamental mechanisms through simple single-well models → conducting progressive research with complex multi-well models”. The single-well mode can ensure the accuracy and interpretability of experimental results, whereas multi-well systems may lose their fundamental research value due to the aforementioned problems. Meanwhile, the permeability measurement of slab cores requires first sealing all end caps, then opening the end cap to be measured for the operation. It should be emphasized that, to ensure the homogeneity of the slab core, the permeability must be measured after assembling each end cap.

4.3. Experimental Results and Comparative Analysis

4.3.1. Comparison of Recovery Degree

By comparing the oil recovery factor curves of the steam huff and puff + SAGD experiment (Figure 10) and the steam huff and puff + chemical flooding + SAGD experiment (Figure 11), it can be observed that both exhibit similar patterns in the primary and secondary steam huff and puff stages: the slopes of the vertical well oil recovery factor curves are similar, both following a linear growth trend, with the final oil recovery rate stabilizing at approximately 11%. The oil displacement mechanism in this stage is dominated by the thermal effect of steam huff and puff. The periodically injected high-temperature steam reduces the viscosity of crude oil through heat conduction and forms “thermal communication channels”, thereby causing the crude oil to drain to the vertical well under the action of gravity and pressure difference [31].

During the critical process divergence stage of 1.6 PV–2 PV, the experiment in Figure 10 proceeds directly to the SAGD stage, while the experiment in Figure 11 incorporates an additional viscosity reducer flooding process. In the conventional SAGD experiment (Figure 10), the oil recovery factor of the vertical well increases rapidly from 11.2% to 18.3%, and the horizontal well is activated simultaneously, contributing 13.8% to the oil recovery rate. In this stage, the steam chamber expands continuously through the vertical well, and steam overriding occurs, forming vertical thermal convection [32]; the gravitational segregation effect drives the heavy oil to flow into the horizontal well. The high slope of the curve indicates that the vertical expansion of the steam chamber is dominant, yet the horizontal well reveals insufficient lateral connectivity to the steam chamber. In contrast, in the experiment with the addition of chemical flooding (Figure 11), the oil recovery factor of the vertical well only increases to 12.8% (with the growth rate being 75% lower than that in the steam huff and puff + SAGD experiment), and the horizontal well contributes 6.2% to the oil recovery rate. The interfacial activity of the viscosity reducer alters the reservoir wettability and inhibits the vertical channeling of steam, resulting in a decrease in the displacement efficiency of the vertical well. However, by reducing the oil–water interfacial tension, the chemical agent forms a “viscosity-reducing front” in the deep part of the reservoir, laying a foundation for optimizing the mobility ratio in the subsequent SAGD stage.

Entering the subsequent SAGD stage (2.0 PV–2.5 PV), both experiments exhibit a “convergence-reversal” trend. In the conventional SAGD experiment (Figure 10), the oil recovery factor of the vertical well decays rapidly, eventually reaching 22.6%, while that of the horizontal well increases to 16.4%, showing a “dual slow-growth” characteristic. This indicates that the vertical expansion of the steam chamber is restricted; the variation in local thermal efficiency is mainly caused by the decreased thermal communication efficiency due to viscous forces, and the oil drainage of the horizontal well is limited by the lateral expansion rate of the steam chamber. In the experiment with chemical flooding added (Figure 11), the oil recovery factor of the vertical well catches up rapidly, eventually reaching 22.0%, while that of the horizontal well surges to 20.1%, presenting a “vertical well compensation + horizontal well surge” characteristic. The viscosity reducer expands the swept volume of the steam chamber through mobility control and simultaneously reduces the residual oil saturation during this stage. In the latter experiment, the viscosity reducer reconstructs the SAGD development performance through the “early energy storage–late release” mechanism: although it sacrifices the short-term productivity of vertical wells, it ultimately achieves an overtake in oil recovery by improving the macroscopic swept efficiency and microscopic oil-washing efficiency of the reservoir [33].

4.3.2. Comparison of Stage Residual Oil Saturation

From the comparison curves in Figure 12, in the two processes of steam huff and puff + SAGD (blue line) and steam huff and puff + chemical flooding + SAGD (orange line), the stage residual oil saturation both decreases with the increase in injection volume. However, for the former process, when the injection volume increases from 0 to 2.507 PV, the residual oil saturation decreases from 79.6% to 46.3%; for the latter process, when the injection volume increases from 0 to 2.6 PV, the residual oil saturation decreases from 80.96% to 38.2%, with a significant difference between the two.

In the steam huff and puff + SAGD process, the primary and secondary huff and puff stages rely on thermal viscosity reduction by steam, leading to a slow decrease in residual oil saturation (only decreasing from 79.64% to 74.00% within the injection volume range of 0 to 0.8 PV). After transitioning to the SAGD stage, the gravity displacement of the steam chamber continuously erodes the residual oil. However, the mobility ratio disparity bottleneck caused by the high viscosity of heavy oil gradually slows down the decreasing rate of residual oil saturation (dropping to 46.3% at an injection volume of 2.5 PV).

In the steam huff and puff + chemical flooding + SAGD process, the viscosity reducer is introduced at approximately 1.8 PV, and it breaks through the (mobility ratio) bottleneck through three mechanisms: firstly, it reduces viscosity to weaken “viscous fingering” and expand the swept volume; secondly, it exerts an emulsifying effect to disperse trapped oil droplets and promote their migration; thirdly, it induces wettability alteration to reduce oil phase adsorption. As a result, the residual oil saturation decreases more sharply after chemical flooding: under the same injection volume, the residual oil saturation of the chemical flooding group is 10–15% lower than that of the pure steam group (e.g., at 2.4 PV, the orange line is approximately 35% while the blue line is approximately 45%). This significantly reduces residual oil trapping, fully demonstrating the critical role of the concentration-based viscosity reducer in enhancing development efficiency and increasing oil production. Additionally, this creates conditions for more uniform expansion of the steam chamber in the subsequent SAGD stage, leading to a steeper downward trend of residual oil saturation.

This difference stems from the “chemical–thermal synergy” established by the viscosity reducer: it not only directly reduces viscosity by disrupting the molecular interactions of resins and asphaltenes, but also optimizes the mobility ratio and enhances steam displacement efficiency. This fundamentally reduces the retention space for residual oil, providing crucial technical support for improving efficiency and increasing production in heavy oil development.

4.3.3. Comparison of Residual Oil Distribution Fields

In the process of SAGD directly conducted after steam huff and puff (Figure 13), the initial oil saturation distribution is relatively uniform; however, the contour lines indicate that the internal heterogeneity of the core exhibits a complex and variable pattern. This characteristic is more consistent with the complex and changeable geological conditions of actual reservoir formations. When the injection volume reaches 0.8 PV (end of primary huff and puff), a significant steam chamber is formed in the near-wellbore area (the steam chamber area appears green, with a decrease in oil saturation). Steam thermal recovery reduces crude oil viscosity and improves its fluidity; meanwhile, steam expansion drives the crude oil, leading to a rapid decrease in oil saturation at the steam front. The dense contour lines in this region form a “thermal gradient zone”. When the experiment proceeds to 1.6 PV (end of secondary huff and puff), the steam chamber expands, but its effective sweep radius is limited, resulting in an uneven distribution of oil saturation. After 1.6 PV, SAGD is initiated. Due to density differences, the steam chamber overrides upward; relying on the gravity drainage mechanism, the oil saturation gradually decreases from the vertical well to the horizontal well direction. When the injection volume reaches 2.53 PV (late SAGD stage), the steam chamber expands fully in the vertical direction, and the blue area (representing low oil saturation) further expands. Nevertheless, there are still residual areas with high oil saturation (shown in red) at the edges, indicating the presence of unswept regions during the development process [32].

Figure 14 illustrates the SAGD process implemented after steam huff and puff combined with a pre-added viscosity reducer flooding stage. During the 0 PV–1.6 PV stage (after completion of primary and secondary huff and puff), the oil saturation trend is completely consistent with that in Figure 13, which confirms the feasibility of comparing the two groups of experiments as parallel samples. In contrast to Figure 13, Figure 14 incorporates a viscosity reducer flooding stage (1.6 PV–1.8 PV). During this stage, the viscosity reducer reduces the oil–water interfacial tension, enabling it to more easily emulsify or dissolve the residual oil on the rock surface. Comparing Figure 13c (1.6 PV, end of steam huff and puff) with Figure 14d (1.8 PV, after chemical flooding), it is observed that the oil saturation in the central region of Figure 14d decreases significantly (with a more continuous green zone), filling the displacement gaps left by steam huff and puff and resulting in a lower stage residual oil saturation. In the subsequent SAGD stage, after the chemical flooding process, the crude oil viscosity (under the combined effect of heat and viscosity reducer) and interfacial tension are further reduced, leading to decreased resistance to steam chamber expansion. At 2.3 PV (Figure 14e), the steam chamber covers the reservoir more efficiently, with a broader low-saturation zone (blue area) and more uniform displacement in the central region. By 2.6 PV (late SAGD stage, Figure 14f), the high-saturation red zones are significantly reduced, and the displacement is more thorough. This reflects the “empowering” effect of chemical flooding on steam chamber expansion in SAGD: the viscosity reducer compensates for the displacement limitations of steam huff and puff, creates more favorable reservoir conditions for SAGD, and ultimately achieves more efficient reduction in oil saturation and mobilization of residual oil, thereby significantly improving the oil recovery factor [34].

5. Conclusions

The core achievement of this study is the establishment of a new evaluation system for the effectiveness of viscosity reducers in extra-heavy oil, with “stage-averaged remaining oil saturation” as the core benchmark. This system overcomes the limitations of traditional evaluation methods, which focus on static conditions, have fragmented indicators, and make it difficult to quantify synergistic effects. Its core lies in progressive experiments of “1D static–2D dynamic–3D synergistic”, whose scientific validity has been fully verified through experiments. The 1D static module serves as the basic screening layer. Through concentration gradient tests, it verifies the system’s ability to identify the “optimal concentration threshold” of viscosity reducers, enabling the definition of a suitable concentration that balances efficiency and economy. This addresses the issue that traditional static evaluation struggles to link with on-site economic efficiency. The 2D dynamic module functions as the process optimization layer. Via sand-packed tube displacement experiments, it verifies the system’s ability to optimize the “viscosity reducer–steam composite process” and identifies the optimal sequence of “steam flooding → viscosity reducer → secondary steam flooding”. This resolves the defect of traditional dynamic evaluation, which is unable to quantify process adaptability. The 3D synergistic module acts as the complex scenario adaptation layer. By simulating post-steam huff and puff SAGD development using slab cores, it verifies the system’s ability to quantify the effect of viscosity reducers under multi-process coupling scenarios, captures their improving effects on residual oil distribution and steam chamber expansion, and fills the gap in traditional evaluation. This system takes “stage-averaged remaining oil saturation” as a consistent metric throughout the entire process, making the effect of viscosity reducers “comparable, quantifiable, and applicable”. Additionally, it clarifies the synergistic mechanism of “chemical empowerment + thermal amplification” of viscosity reducers, providing full-process guidance for “concentration screening–process design–effect prediction” in on-site steam–chemical composite flooding. It serves as a key support for the efficient and economical development of extra-heavy oil.

6. Discussion

(1)

It is worth noting that this study aims to establish an evaluation system for the effectiveness of viscosity reducers. However, the investigation on the timing of flooding conversion is limited to the viscosity reducer used in this study, and further experimental investigations are required for the exploration of other types of viscosity reducers. Meanwhile, water-soluble tracers can be added during the experiment to determine the amount of oil contacted [35]. Additionally, after the experiment, it would be of great significance to cut cross-sectional thin sections along the core and measure the average oil saturation at various positions of the core.

(2)

To further improve the research accuracy, the optimized experimental design adopts actual reservoir cores instead of sand-packed tubes and combines CT scanning technology to real-time monitor the oil saturation distribution during the displacement process. It also explores the “viscosity reducer-SAGD-CO₂” ternary composite technology [36,37]: leveraging the synergistic effect of CO₂ (with swelling and viscosity reduction properties) and the interfacial activity of viscosity reducers to reduce crude oil viscosity; meanwhile, the low-density characteristic of CO₂ alleviates the steam overriding issue and improves the vertical sweep efficiency [38]. Additionally, the evaluation system established in this study demonstrates significant advantages compared with polymer surfactant (PS) [39,40], nanoparticle (NP), and CO₂-assisted systems: For PS, its evaluation is isolated and lacks core indicators, whereas this system forms a “parameter-process-field” closed loop based on core indicators [41]; For NP, its evaluation lacks macro-micro correlation, while this system achieves dual-scale synergy between the viscosity reducer’s mechanism of action and steam chamber expansion; For CO₂-assisted systems, their evaluation lacks stage-specific decomposition, but this system clarifies the “chemical–thermal” synergistic mechanism and dismantles efficiency-enhancing links through staged residual oil saturation. The “viscosity reducer-SAGD-CO₂” ternary composite technology focuses on the steam overriding problem in gravity drainage-assisted steam flooding. It deduces a steam overriding coefficient model based on “pressure gradient–vapor-liquid density difference” and reveals the law that the “lag” of vapor phase migration behind the isobaric surface of the oil–water liquid phase, as well as the improvement effect of well pattern regulation on overriding. However, it fails to incorporate three aspects: the influence of viscosity reducers on steam overriding, the correction effect of CO₂ on vapor-liquid density difference and pseudo mobility ratio, and the correlation with quantitative evaluation of residual oil saturation. In the future, based on the above two (the established evaluation system and the ternary composite technology), efforts should be made to address the limitations of the former’s homogeneous experiments and the latter’s overriding theory: deepen the dynamic correction of the overriding coefficient under the “viscosity reducer-CO₂-steam” ternary system; improve the “horizontal priority” regulation technology for steam chamber expansion in heterogeneous/middle-deep reservoirs; establish a full-scale evaluation system covering microscale interfacial interactions (molecular adsorption among viscosity reducer, CO₂, and crude oil), mesoscale pore flow (CT-monitored fluid distribution), and macroscale reservoir development (dual indicators of residual oil saturation and overriding degree); break through the limitations of the former’s single switchover timing of flooding and the latter’s non-intelligent well pattern regulation, and realize dynamic optimization of injection-production parameters through real-time monitoring and intelligent algorithms. Ultimately, these efforts will promote the field application of thermal-chemical-CO₂ synergistic development for extra-heavy oil [42], while simultaneously optimizing the matching scheme of well type combination and development method for maximizing recovery efficiency.

(3)

While sand-packed tubes and small-scale 3D models can focus on the core mechanism of viscosity reducer effectiveness, they have significant limitations. For sand-packed tubes: Distortion of reservoir heterogeneity (lack of interbeds, fractures, and permeability differences, making it difficult to reflect steam channeling and residual oil retention in low-permeability zones), obvious scale effect (deviation between small-scale boundary effects and on-site flow laws over hundreds of meters), single rock surface property (pure quartz sand ignores the influence of clay adsorption and organic matter on wettability), and simplified fluid phase behavior (fixed simulated oil viscosity and low salinity, failing to cover the complexity of on-site fluid components and ions) leading to overestimated oil recovery and viscosity reduction efficiency. For small-scale 3D models: Insufficient reservoir scale (inability to simulate steam chamber expansion and heat loss), simplified well pattern and process (lack of completion structure and actual well spacing), unmodeled long-term dynamic changes in reservoirs (ignoring clay swelling and asphaltene deposition), and simplified multi-physics field coupling (no inhomogeneity of stress and chemical fields) result in conclusions on viscosity reducer efficiency enhancement in SAGD development that are difficult to be applied in field practice. To address these issues, it is necessary to establish an adaptability bridge with on-site conditions by introducing heterogeneity simulation, increasing model scale, and combining numerical simulation for scaling-up. In the practical reservoir application: Regarding heterogeneity: Referring to the characteristics of “high-permeability zones being developed first and low-permeability zones retaining oil” in 2D sand-packed tubes and uniform steam chamber expansion in 3D models, layered injection is adopted (composite system of viscosity reducer and weak profile control agent for high-permeability zones, composite process for medium-low permeability zones, and CO₂ supplementation for ultra-low permeability zones). Tracers and numerical simulation are combined to calibrate residual oil distribution. Regarding pressure differences: Based on the constant-rate displacement and confining pressure in experiments, injection-production intensity is adjusted according to pressure gradients (“low-intensity steam + high-concentration viscosity reducer” for high-pressure zones, “enhanced steam + 0.8% concentration viscosity reducer” for low-pressure zones). The “vertical well huff and puff + horizontal well SAGD” mode is used to balance pressure. Regarding economic constraints: Viscosity reducers are customized in batches at the optimal economic concentration. The injection volume is optimized with reference to the slug volume in 2D experiments and the steam dosage in 3D secondary steam flooding, and the cost and oil recovery are verified through small well groups.